Extracting sv shear data from p-wave marine data

ABSTRACT

A system and method of processing seismic data obtained using a plurality of towed single-component receivers in a marine environment is described, the towed single-component receivers configured to measure compressional P waves. The method comprises retrieving seismic data from a storage device, the seismic data comprising P-P data and shear mode data, wherein the P-P data and shear mode data were both received at the towed single-component receivers configured to measure compressional P waves to generate the seismic data. The method further comprises processing the seismic data to extract SV-P shear mode data and generating shear mode image data based on the extracted shear mode data.

CROSS REFERENCE TO RELATED APPLICATIONS

This application is a continuation of U.S. application Ser. No.15/084,830 filed Mar. 30, 2016, which is a continuation of U.S.application Ser. No. 13/663,081 filed Oct. 29, 2012, which is acontinuation of U.S. application Ser. No. 13/413,562 filed Mar. 6, 2012,which is a continuation-in-part application of U.S. application Ser. No.13/287,746, filed Nov. 2, 2011, which is a continuation-in-partapplication of U.S. application Ser. No. 13/217,064, filed Aug. 24, 2011titled “System and Method for Acquisition and Processing of ElasticWavefield Seismic Data,” which is a continuation application of U.S.application Ser. No. 12/870,601, filed Aug. 27, 2010 titled “System andMethod for Acquisition and Processing of Elastic Wavefield SeismicData,” all of which applications are incorporated by reference herein intheir entireties.

BACKGROUND

The present application relates generally to systems and methods forseismic exploration, including the acquisition and/or processing ofseismic data to estimate properties of the Earth's subsurface.

The principal type of data used to explore for oil and gas resources isseismic reflection data that image subsurface geology. There are threeseismic wave modes that can be used for subsurface imaging—acompressional-wave (P) mode and two shear-wave modes (SV and SH). Whengeophysicists acquire seismic data that have all three of these modes,the data are called full elastic-wavefield data. Full elastic-wavefielddata are acquired by deploying three separate orthogonal seismic sourcesat every source station across a prospect area. One source applies avertical force vector to the Earth, a second source applies a horizontalforce vector in the inline (X) direction, and a third source applies asecond horizontal force vector in the crossline (Y) direction.

The wavefields produced by each of these three orthogonal-force sourcesare recorded by 3-component geophones that have orthogonal (XYZ) sensingelements. The resulting data are called 9-component data because theyconsist of 3-component data produced by three different sources thatoccupy the same source station in sequence, not simultaneously. Fulldescriptions and illustrations of the sources, sensors, and fieldprocedures used to acquire full elastic-wavefield data can be found inChapter 2, Multicomponent Seismic Technology, Geophysical ReferencesSeries No. 18, Society of Exploration Geophysicists, authored by B. A.Hardage, M. V. DeAngelo, P. E. Murray, and D. Sava (2011). Vertical,single-component, surface-based geophones are used for the purpose ofacquiring P-wave seismic data.

Marine seismic data are generated by an air gun source (e.g., an air gunarray) towed a few meters (e.g., 3 to 15 m) below the sea surface. Dataare recorded by a long cable (e.g., as long as 10 or 15 km) that hashydrophones spaced at intervals of a few meters (e.g., 10 to 20 m).Several of these hydrophone cables can be towed by the same boat thattows the air guns, or the source and the hydrophone cables can be towedby separate boats. Sometimes there are two cable boats moving alongparallel tracks, maybe 6 or 8 km apart, and each towing 10 or morecables as long as 15 km that span a lateral distance of 1 to 2 km. Inthese modern long-offset, multi-azimuth marine surveys, there are 2 to 4source boats stationed around the cable boats. The whole procedureinvolves a small armada moving at a slow speed with each boat performingits assignment with precise GPS positioning and atomic-clock timing. Theamount of data recorded across a large survey area can be staggering.

Water has a shear modulus of zero, thus S waves cannot propagate in seawater. Because a marine source and receiver are in a water layer, marineseismic data are considered to be only P-wave data.

SUMMARY

A system and method of processing seismic data obtained using a towedreceiver in a marine environment is described, the towed receiverconfigured to measure compressional P waves. The method comprisesretrieving seismic data from a storage device, the seismic datacomprising P-P data and shear mode data, wherein the P-P data and shearmode data were both received at the towed receiver configured to measurecompressional P waves to generate the seismic data. The method furthercomprises processing the seismic data to extract SV-P shear mode dataand generating shear mode image data based on the extracted shear modedata.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a diagram illustrating a full-elastic, multicomponent seismicwavefield propagating in a homogeneous Earth, according to an exemplaryembodiment.

FIG. 2 is a diagram showing SH and SV shear wave displacements,according to an exemplary embodiment.

FIG. 3 is a map view of SH and SV illumination patterns for orthogonal(X and Y) horizontal-displacement sources.

FIG. 4 is a comparison of SH, SV and P velocity behavior for elasticwave propagation in horizontally layered media.

FIG. 5 is a cross-sectional view of a theoretical calculation of P andSV radiation patterns produced when a vertical force F is applied to thesurface of the Earth, shown for two different values of the Poisson'sratio of the Earth layer, according to an exemplary embodiment.

FIGS. 6A and 6B show an S-wave radiation pattern from FIG. 5 displayedas a 3D object, according to an exemplary embodiment.

FIG. 7A is a chart of VSP data acquired using a vertical-displacementsource, according to an exemplary embodiment.

FIG. 7B is a chart of VSP data acquired using a vertical-displacementsource, according to an exemplary embodiment.

FIG. 8 is a diagram showing a source-receiver geometry used to analyze Pand S radiation patterns emitted by seismic sources, according to anexemplary embodiment.

FIG. 9 is a diagram illustrating takeoff angle apertures, according toan exemplary embodiment.

FIG. 10 is a diagram illustrating transformation of X, Y, Z receivers toP, SV, SH receivers, according to an exemplary embodiment.

FIG. 11 is a set of charts showing example X, Y, Z data acquired with avertical array from a vertical-impact source, and corresponding datarotated to P, SV and SH data space, according to an exemplaryembodiment.

FIG. 12 is a set of charts showing example X, Y, Z data acquired with avertical array from a shot hole explosive source, and corresponding datarotated to P, SV and SH data space, according to an exemplaryembodiment.

FIG. 13 is a set of charts showing example X, Y, Z data acquired with avertical array from a vertical vibrator source, and corresponding datarotated to P, SV and SH data space, according to an exemplaryembodiment.

FIG. 14 is an illustration of the principle of data-polarity reversalsapplied to vertical-force source data to create constant-polarity S-wavedata across seismic image space, according to an exemplary embodiment.

FIG. 15 illustrates a first example of polarities of vertical-forceseismic data and the result of reversing polarities in thenegative-polarity domain to convert vertical-force source data toconstant-polarity dipole-source data, according to an exemplaryembodiment.

FIG. 16 illustrates a second example of polarities of vertical-forceseismic data and the result of reversing polarities in thenegative-polarity domain to convert vertical-force source data toconstant-polarity dipole-source data, according to an exemplaryembodiment.

FIG. 17 is a block diagram of a data acquisition and processing systemand method for acquiring and processing full elastic waveform data froma vertical-force source using surface-based sensors, according to anexemplary embodiment.

FIG. 18 is a block diagram of a data acquisition and processing systemand method for acquiring and processing full elastic waveform data froma vertical-force source using sub-surface sensors, according to anexemplary embodiment.

FIG. 19 is a block diagram of a data processing system for processingfull elastic wavefield data, according to an exemplary embodiment.

FIG. 20 is a flow diagram illustrating a method of processing fullelastic wave data, according to an exemplary embodiment.

FIG. 21 is a raypath diagram illustrating a comparison of P-P and SV-Pimaging of subsurface geology, according to an exemplary embodiment.

FIG. 22 is a raypath diagram illustrating an approach direction ofupgoing P-P and SV-P raypaths at a receiver station when the top Earthlayer is low-velocity unconsolidated sediment, according to exemplaryembodiment.

FIG. 23 is a raypath diagram showing principles of SV-SV and SV-Pimaging, according to an exemplary embodiment.

FIG. 24 is a raypath diagram showing approach direction of upgoing P andSV raypaths at a receiver stations when the top Earth layer ishigh-velocity rock, according to an exemplary embodiment.

FIG. 25 is a raypath diagram illustrating a comparison of P-SV and SV-Praypaths, according to an exemplary embodiment.

FIGS. 26A and 26B are exemplary diagrams illustrating size and positionof SV-P image space for a 3D P-wave data-acquisition geometries.

FIG. 27 is a diagram of a subsurface geology illustratingpositive-offset and negative-offset domains for SV-P data and Facies Aand B causing different velocities, according to an exemplaryembodiment.

FIGS. 28A and 28B are examples of SV-P primary and multiple reflectionsextracted from vertical-geophone P-wave seismic data, according to anexemplary embodiment.

FIG. 29 is a diagram illustrating SV-P and P-SV CCP imaging principles,according to an exemplary embodiment.

FIG. 30 is a diagram and table illustrating prestack migration,according to an exemplary embodiment.

FIG. 31 is a tabulation of some similarities and differences betweenSV-P and P-SV data, according to an exemplary embodiment.

FIG. 32 is a block diagram of a data processing system for processingshear wave data from a vertical sensor, according to an exemplaryembodiment.

FIG. 33 is a block diagram of a data acquisition and processing systemand method for acquiring and processing shear wave data from avertical-force source using surface-based sensors, according to anexemplary embodiment.

FIG. 34 is a flow diagram illustrating a method of processing shear wavedata from a vertical receiver in a situation involving a low-velocityEarth surface, according to an exemplary embodiment.

FIG. 35 is a flow diagram illustrating a method of processing shear wavedata from a vertical receiver in a situation involving a high-velocityEarth surface, according to an exemplary embodiment.

FIG. 36 is a diagram of approach angles of P waves to a verticalgeophone, according to an exemplary embodiment.

FIG. 37 is a diagram of approach angles of SV waves to a verticalgeophone, according to an exemplary embodiment.

FIG. 38 is a schematic diagram of equipment used in marine seismic dataacquisition and raypaths of seismic modes, according to an exemplaryembodiment.

FIG. 39 is a schematic diagram illustrating raypaths associated with avirtual seafloor source and a virtual seafloor receiver, according to anexemplary embodiment.

FIG. 40 is a diagram of a subsurface geology illustratingpositive-offset and negative-offset domains for SV-P data and Facies Aand B causing different velocities, according to an exemplaryembodiment.

FIG. 41 is a diagram illustrating (a) positive-offset marine data, (b)negative-offset marine data, and (c) a combination of positive-offsetand negative-offset marine data, according to an exemplary embodiment.

FIG. 42 illustrates SV-P and P-SV CCP imaging principles, according toan exemplary embodiment.

FIG. 43 illustrates a time-space distribution of velocities for eachspecific seismic mode, according to an exemplary embodiment.

FIG. 44 is an exemplary calculation used in prestack time migration ofseismic data, according to an exemplary embodiment.

FIG. 45 is a flow diagram illustrating a process of prestack timemigration, according to an exemplary embodiment.

FIG. 46 is a flowchart illustrating a system and method for processingmarine SV-P data, according to an exemplary embodiment.

FIG. 47 is a system diagram illustrating a system for acquisition andprocessing of marine SV-P data, according to an exemplary embodiment.

DETAILED DESCRIPTION OF EXEMPLARY EMBODIMENTS

One or more embodiments described herein may provide a method by whichfull elastic-wavefield seismic data (P, SV and SH modes) can be acquiredand processed using only one source, a vertical-force source. Theembodiments may be simpler and lower-cost than using threeorthogonal-force sources. The embodiments may be used in oil and gasexploration and exploitation, or any other activity where seismicreflection data are widely used. The embodiments may remove numeroustechnical, environmental, and cost barriers that limit applications offull elastic-wavefield seismic data.

One or more embodiments described herein may involve departures fromconventional seismic data processing strategy.

One or more embodiments described herein may reduce the cost ofacquiring complete elastic-wavefield seismic data. The daily rate forutilizing a single vertical-force source is less than the rates ofdeploying both a vertical-force source and a horizontal-force source toacquire equivalent data. Further, data may be acquired quicker bydeploying a single source at each source station to create fullelastic-wavefield data rather than deploying a vertical-force source anda horizontal-force source. The longer a contractor works to acquiredata, the greater the cost of the data.

One or more embodiments described herein may provide the ability toacquire elastic-wavefield seismic data across a wider range of surfaceconditions, such as swamps, marshes, rugged mountain terrain, densetimber, and agricultural regions. Vertical-force sources can operate ina wide variety of surface terrains. For example, shot hole explosivescan be used in swamps, marshes, heavy timber, or rugged mountains, allof which are places horizontal sources cannot be deployed at all, or atgreat cost because of site preparations. Vertical vibrators can bedeployed in high-culture and residential areas without causing physicaldamage to buildings and infra-structure.

One or more embodiments described herein may provide a wider choice ofseismic sources. There is a limited choice of horizontal-force seismicsources—such as heavy, horizontal vibrators or inclined-impact sources.The total number of horizontal vibrators across the world is small. Thenumber of inclined-impact sources is less. More of each type of sourcecould be manufactured if demand appears. In contrast, there are hundredsof vertical-force sources. The dominating classes of vertical-forcesources are vertical vibrators (hundreds around the world) and shot holeexplosives (available anywhere). Vertical-impact sources are few, butthey too can be manufactured in mass if a market is created. Forvertical seismic profile (VSP) data acquisition in remote areas (forexample equatorial jungles), an air gun fired in a mud pit would be avertical-force source. One or more embodiments described herein mayallow geoscientists to select from a large menu of vertical-forcesources: vertical vibrators, shot-hole explosives, vertical-impactors,or mud pit air guns.

Wave Components

Referring to FIG. 1, a full-elastic, multicomponent seismic wavefieldpropagating in a simple homogenous Earth is illustrated. Threeindependent, vector-based, seismic wave modes propagate in the Earth: acompressional mode, P, and two shear modes, SV and SH (FIG. 1). Eachmode travels through the Earth at a different velocity, and each modedistorts the Earth in a different direction as it propagates.Double-headed arrows 102 are particle-displacement vectors indicatingthe direction in which each mode displaces the Earth. Arrows 104illustrate a direction of wave propagation. Acquisition of themulticomponent modes results in full elastic-wavefield data. Theorientations of the P, SV, and SH displacement vectors relative to thepropagation direction of each mode are illustrated in FIG. 1.

The propagation velocities of the SH and SV shear modes may differ byonly a few percent, but both shear velocities (V_(S)) are significantlyless than the P-wave velocity (V_(P)). The velocity ratio V_(P)/V_(S)can vary by an order of magnitude in Earth media, from a value of 50 ormore in deep-water, unconsolidated, near-seafloor sediment to a value of1.5 in a few dense, well-consolidated rocks.

Referring to FIG. 2, an exemplary distinction between SH and SV shearmodes is illustrated. SH and SV shear modes may be distinguished byimagining a vertical plane passing through a source station A and areceiver station B. SV vector displacement occurs in this verticalplane, as indicated at arrow 202; SH vector displacement is normal tothe plane, as indicated at arrow 204. This vertical plane passingthrough the coordinates of a source station A, a receiver station B, anda reflection point C or D produced by that source-receiver pair may becalled a sagittal plane or propagation plane.

Horizontal-Force Sources and SH/SV Illumination

Referring to FIG. 3, a map view of theoretical SH and SV radiationpatterns produced by orthogonal horizontal-displacement sources 302, 304will be described. Mathematical expressions that describe thegeometrical shape of P, SV, and SH radiation patterns produced byseismic sources in an isotropic Earth are described by White (1983).Viewed from directly above the horizontal-displacement source, SV and SHmodes propagate away from the source stations 302, 304 as expandingcircles or ellipses. To simplify the graphic description, the patternswill be shown as circles. Because SV radiation from ahorizontal-displacement source 302, 304 is usually more energetic thanSH radiation, SV radiation circles are drawn larger than SH radiationcircles. These circles indicate which parts of the image space each modeaffects and the magnitude of the mode illumination that reaches eachimage coordinate. The relative sizes of these circles are qualitativeand are not intended to be accurate in a quantitative sense.

A horizontal source-displacement vector 306 oriented in the Y direction(left side of figure) causes SV modes to radiate in the +Y and −Ydirections and SH modes to propagate in the +X and −X directions. Ahorizontal source-displacement vector 310 oriented in the X direction(right side of figure) causes SV modes to radiate in the +X and −Xdirections and SH modes to propagate in the +Y and −Y directions. If aline is drawn from the source station 302, 304 to intersect one of theseradiation circles, the distance to the intersection point indicates themagnitude of that particular mode displacement in the azimuth directionof that line. The orientation of the particle-displacement vectors 308and 312 remains constant across the image space, but the magnitude ofthe SH and SV particle-displacement vectors vary with azimuth as shownby the SH and SV radiation circles on FIG. 3.

Referring to FIG. 4, velocity behavior of SH and SV modes propagatingthrough a layered Earth have been described by Levin, F., 1979, Seismicvelocities in transversely isotropic media I: Geophysics, 44, 918-936and Levin, F., 1980, Seismic velocities in transversely isotropic mediaII: Geophysics, 45, 3-17. The layered Earth is horizontally layered,vertical transverse isotropic (VTI) media. Note that at all take-offangles (except angle 402) SV and SH propagate with different velocities,with SH having a significantly faster velocity at shallow take-offangles (such as angle 404) from a source station 406. This wave physicswill be useful when examining seismic test data described later.

Vertical-Force Sources and Direct-S Illumination

One type of source used in onshore seismic data acquisition applies avertical displacement force to the Earth. Among these vertical-forcesources are vertical weight droppers and thumpers, explosives in a shothole, and vertical vibrators. Such sources are traditionally viewed asonly P-wave sources, but they also produce robust S wavefields.

Referring to FIG. 5, an illustration of a theoretical calculation, incross-sectional views, is presented to illustrate how energy isdistributed between P-wave and SV-shear mode radiation patterns when avertical force is applied to an elastic half-space 502 from a verticalforce source or vertical displacement source. See Miller, G., and H.Pursey, 1954, The field and radiation impedance of mechanical radiatorson the free surface of a semi-infinite isotropic solid: Proc. Royal Soc.London, Series A, v. 223, p. 521-541 and White, J. E., 1983, Undergroundsound—applications of seismic waves: Elsevier Science Publishers.Calculations are shown for two different values of the Poisson's ratioof the Earth layer, with the first image 500 representing a Poisson'sratio of 0.44 and the second image 502 representing a Poisson's ratio of0.33. This analysis focuses only on body waves and ignores horizontallytraveling energy along the Earth-air interface. The semi-circlesindicate the relative strength of the radiation. Radial lines define thetake-off angle relative to vertical. In each model, more SV energy isgenerated than P energy.

The calculation of FIG. 5 shows that a vertical-force source 504produces more SV energy 506 than P energy 508, and that at take-offangles of 20-degrees and more this direct-SV mode is significantlystronger than the P mode. This particular SV radiation may not result ina robust illumination of geology directly below the source station;whereas, its companion P radiation does. In order to take advantage ofthe direct-SV mode produced by vertical displacement onshore sources,two features can be implemented in data acquisition systems. First,three component (3C) geophones are used rather than single-componentgeophones. Second, longer recording times are used to accommodate theslower propagation velocity of the downgoing and upgoing direct-SV mode.For example, P-wave recording times of four seconds to six seconds maybe extended to at least eight seconds or at least 12 seconds. Recordingtimes for large offsets between source and receiver may be at leastthree times or at least four times the vertical travel time to thedeepest target of interest. Modern seismic data acquisition systems canaccommodate the long data-acquisition times required to image deeptargets at far-offset receiver stations. A processing circuit within thedata acquisition system may be configured to control the geophones orother receivers or sensors to listen or record received seismic data forat least a minimum recording time.

A definitive way to illustrate the P and direct-SV radiation produced bya vertical-displacement source is to analyze its downgoing wavefieldusing vertical seismic profile (VSP) data. One example of VSP dataacquired in the Delaware Basin of New Mexico with a vertical vibratorused as a source is provided as FIG. 7A. The downgoing mode labeled SVis not a tube wave because it propagates with a velocity ofapproximately 2400 m/s (8000 ft/s), which is almost twice the velocityof a fluid-borne tube wave. The downgoing P and SV illuminating waveletsproduced immediately at the point where this vibrator applies a verticalforce to the Earth surface are labeled and extended back to the surfacesource station 700 to illustrate that an SV mode is produced directly atthe source. The absence of data coverage across the shallowest 3000 ftof strata leaves some doubt as to where downgoing event SV is created,so a second example of VSP data produced by a vertical vibrator in aSouth Texas well is illustrated on FIG. 7B. Again thisvertical-displacement source creates a robust direct-SV wavefield inaddition to the customary P wavefield. In this example, the downgoing SVmode can be extended back to the source station at the Earth surfacewith confidence. In the case of FIG. 7B, the source was offset only 100ft from the VSP well. The top diagram shows a vertical geophoneresponse. The bottom diagram shows the response of a horizontalgeophone.

The VSP data examples of FIGS. 7A and 7B show that a vertical vibratoris an efficient producer of direct-SV radiation and creates an SV-SVmode that can be utilized. An explosive shot also applies avertical-displacement force to the Earth and generates a direct-SV mode.

The SV mode exhibited by the data in FIGS. 7A and 7B is produced at thesame Earth coordinate as the P mode and is a source-generated direct-SVwave. The propagation medium at this location has unusually low V_(P)and V_(S) velocities. The SV mode produces a large population of upgoingSV reflections that are observable in these raw, unprocessed data.

The term “SV” is used above to describe the S-wave radiation. However,as will be seen below, the term “SV” should be replaced with the broaderterm “S”, meaning the radiated S-wave energy is both SV and SH when theradiation is considered in a 3D context rather than as a single verticalprofile.

To illustrate the principle that S-wave radiation produced by avertical-force source consists of both SV and SH modes, the patterndisplayed on the right of FIG. 5 is converted to a 3D object anddisplayed as FIGS. 6A and 6B. For ease of understanding, the 3Dradiation pattern is simplified to contain only the major S lobe 512,514 shown in FIG. 5. Both the P-wave component 516 and the smallersecondary S lobe 518 seen on FIG. 5 are omitted. The solid is furtheraltered by removing a 90-degree section 602 to allow better viewing ofthe 3D geometry by which S energy spreads away from the vertical-forcesource station VFS.

In FIG. 6A, SV and SH planes and displacement vectors are shown relativeto a receiver station R_(A). In FIG. 6B, SV and SH planes anddisplacement vectors are drawn relative to a receiver station R_(B).These two arbitrary receiver stations R_(A) and R_(B), separated by anazimuth of 90 degrees, are positioned on the Earth surface around astation VFS where a vertical-force source is deployed. Oblique views andmap views are shown of a vertical plane passing through the sourcestation and each receiver station. As discussed for FIG. 2, thissource-receiver plane is the SV plane for each receiver station. Foreach receiver, an SH plane is also shown perpendicular to each SV plane.The SH plane for receiver R_(A) is the SV plane for receiver R_(B), andinversely, the SH plane for receiver R_(B) is the SV plane for receiverR_(A). Regardless of where a receiver station is positioned in azimuthspace away from a vertical-force station, both SV and SH modes willpropagate to that station. SH shear information is available as is SVshear information when vertical-force source data are acquired.

Field Test

The Exploration Geophysics Laboratory (EGL) at the Bureau of EconomicGeology initiated a field-test program to quantify the geometricalshapes and relative strengths of compressional (P)-wave and shear(S)-wave modes produced by a variety of seismic sources. The first testprogram was done at the Devine Test Site owned by The University ofTexas at Austin and managed by EGL researchers. Sources deployed forthis initial test were: 1-kg package of explosive positioned at a depthof 20 ft, a horizontal vibrator, a vertical vibrator, and anaccelerated-weight that impacted the Earth vertically and at inclinedangles.

Source-Receiver Geometry

Referring to FIG. 8, an illustration of the source-receiver geometry isshown. The source-receiver geometry used to evaluate P and S sourceradiation patterns combined the concepts of horizontal wave testing(involving only a horizontal receiver array) and vertical wave testing(involving only a vertical receiver array) as described by Hardage, B.A., 2009, Horizontal wave testing: AAPG Explorer, v. 30, no. 12, p.26-27 and Hardage, B. A. 2010, Vertical wave testing: AAPG Explorer, v.31, no. 1, p. 32-33. A 24-station vertical array of three-componentgeophones was deployed in a selected test well, with receiver stationsspanning a depth interval extending from 500 to 1632 ft (FIG. 8).Three-component (3C) geophones are configured to acquire all threedimensions of a full elastic wave. Several 25-station horizontal arraysof 3C sensors spaced 10 ft apart spanned the offset range 0 to 250 ftimmediately next to the receiver well. Source stations were offset fromthe well at intervals of 250 ft, the linear dimension of the horizontalsurface-receiver arrays.

Vertical Aperture

Referring to FIG. 9, an approximation of the aperture range created bythe source-receiver geometry is shown. Downgoing P and S modes wererecorded over a wide aperture of vertical takeoff angles (14 degrees to81 degrees in this example) from the surface source stations to definethe geometrical shape of P and S radiation patterns in section view. Theshallowest takeoff angle involved data generated at source station 9(offset 1920 ft) and recorded at downhole receiver station 24 (depth of500 ft). The steepest takeoff angle involved source station 2 (offset250 ft) and downhole receiver station 1 (depth of 1632 ft). A firstapproximation of the aperture range created by the source-receivergeometry can be created by assuming straight raypaths from source todownhole receiver, which yields the result shown in FIG. 9. In actualwave propagation, raypaths are curved as dictated by refractions atinterfaces between velocity layers. Raypaths refract (bend) when theyadvance from an Earth layer having velocity V1 into a layer havingvelocity V2. Raypath curvature can be calculated if velocity layering isknown. Straight raypath assumptions are used to explain the principlesdescribed with reference to FIG. 9.

Transforming VSP Data to Wave-Mode Data

In a vertical well, azimuth orientations of X,Y horizontal geophonesdeployed by twisted-wire cable differ at each downhole station becauseof receiver-module spin. As a result, phase shifts and amplitudevariations introduced into data by station-to-station variations inreceiver orientation do not allow individual events or distinct wavemodes to be recognized, particularly S-wave events that tend to dominatehorizontal-sensor responses. In this case, receivers are mathematicallyoriented to specific azimuths and inclinations to define downgoing andupgoing P and S modes.

Referring to FIG. 10, a graphical description of the transformation ofreceivers from X, Y, Z data space to P, SV, SH data space is shown.Transformations of borehole receivers from in situ X, Y, Z orientationsto a data space where receivers are oriented to emphasize P, SV, and SHevents have been practiced in vertical seismic profiling (VSP)technology. DiSiena, J. P., Gaiser, J. E., and Corrigan, D., 1981,Three-component vertical seismic profiles—orientation of horizontalcomponents for shear wave analysis: Tech. Paper S5.4, p. 1990-2011,51^(st) Annual Meeting of Society of Exploration Geophysicists. Hardage,B. A., 1983, Vertical seismic profiling, Part A, principles: GeophysicalPress, 450 pages (The VSP Polarization Method for Locating Reflectors,pages 307-315). Examples of this receiver orientation procedure appliedto vertical-impact, shot-hole explosive, and vertical-vibrator sourcesat selected source stations are illustrated on FIGS. 11, 12, and 13,respectively. Data windows spanning 100 ms immediately following theonset of interpreted P-wave direct arrivals were used to determineazimuth and inclination angles θ and Φ (FIG. 10) at each receiverstation.

FIG. 10 illustrates a 2-step rotation of coordinate axes to determinedirectional angles from a subsurface receiver to a surface-positionedseismic source. When a 3-component sensor is lowered several hundreds offeet down a well, the azimuth orientations of horizontal sensors are notknown because the receiver package rotates on the twisted wire cableused for deployment. As a consequence, P, SH, and SV modes areintermingled on each sensor response because sensors are not oriented inthe directions of P, SV, and SH particle displacements. Therefore, eachsubsurface receiver is mathematically oriented so that one sensor pointsdirectly along the raypath of the downward traveling P wave from asurface source. Once such rotation is done, the sensor pointing at thesource is dominated by P data, the second sensor in the same verticalplane as the P sensor (this vertical plane passes through the source andreceiver stations) is dominated by SV, and the third sensor(perpendicular to this vertical plane) is dominated by SH. Two angles—ahorizontal rotation angle θ and a vertical rotation angle Φ—have to bedetermined to achieve this sensor orientation.

To determine horizontal azimuth angle θ (FIG. 10), data are analyzed ina short time window spanning only the downgoing P-wave first arrivalfrom the source. Only responses of the two horizontal sensors X and Yare analyzed in this first rotation step. Data acquired by sensors X andY are mathematically transformed to responses that would be observed ifthese two orthogonal sensors were rotated to new coordinate axes thatare successively incremented by one-degree of azimuth. This rotation isdone 180 times to create sensor responses that allow the sensor axes topoint over an azimuth range of 180 degrees from the unknown azimuth inwhich the sensors actually point. When sensor X is positioned in thevertical plane passing through the receiver and the source, the responseof the X sensor will be a maximum, and the response of the Y sensor willbe a minimum. When this maximum-X and minimum-Y response is found, theangle between the in situ sensor axes and the desired rotated axes thatisolate P, SV, and SH wave modes is θ.

To determine inclination angle Φ (FIG. 10), the sensor responses aftertransforming the data to coordinate axes oriented in azimuth θ are thenanalyzed in the short data window spanning only the downgoing P-wavefirst arrival, as defined in this new data-coordinate space. Data fromonly sensor Z (vertical) and from the new X sensor that has been rotatedinto the vertical source-receiver plane are used in this secondrotation. In this second axis rotation, these two sensor responses aremathematically transformed to responses that would be observed if thesetwo sensors were tilted in successive inclinations of one degree of tiltover a tilt range of 90 degrees. When the Z receiver is pointing in thedirection of the incoming P-wave first arrival, its response will be amaximum, and the companion sensor in the same vertical plane (the newrotated and tilted X sensor) response will be a minimum. When thiscondition is found, angle Φ has been defined.

Data transformed to this second coordinate system defined by an azimuthrotation of θ and an inclination angle of Φ have optimal separation ofP, SV, and SH modes, with P, SV, and SH being the dominant data on therotated and tilted Z, X, and Y sensors, respectively.

Referring to FIG. 11, charts 1100, 1102 and 1104 illustrate X, Y, Z dataacquired at the Devine Test Site with the vertical receiver array when avertical-impact source was positioned at source station 9, offset 1920ft from the receiver array. Charts 1106, 1108 and 1110 illustrate thesame data rotated to P, SV, SH data space. No P or SV events appear onthe SH data panel. Because SH displacement is orthogonal to both P andSV displacements, the absence of P and SV events defines SH data. SVevents appearing on the P data panel such as the event shown at 1112 aredowngoing P-to-SV conversions. Downgoing P-to-SV conversions are causedonly by non-normal incidence of a P wave on an impedance contrastinterface. P and SV modes exchange energy freely when reflecting andrefracting at interfaces because the displacement vectors of these twomodes are in the same vertical plane. Neither P nor SV can convertenergy to SH, and conversely SH can not convert into P or SV, because SHdisplacement is orthogonal to the vertical plane in which P and SVpropagate. To confirm that a data panel is an SH mode, we search forevidence of P and SV events embedded in the data panel. If no P or SVevents can be identified, the mode is pure SH, by definition. Note atshallow take-off angles (top 4 or 5 receiver stations), SH waves travelfaster than SV waves as predicted by Levin (1979, 1980), supra, andmeasured by Robertson, J. D. and D. Corrigan, 1983, Radiation patternsof a shear-wave vibrator in near-surface shale: Geophysics, 48, 19-26.

SV waves produced directly at the source means SV waves are generatedexactly at the point where a vertical force is applied to the Earth.There does not have to be an impedance-contrast interface close to thesource to cause SV to come into existence. SV will propagate away from avertical-force source even in a thick, homogeneous medium in which thereare no interfaces.

In contrast, P-to-SV conversions occur only at interfaces where there isan impedance contrast. Any time a P-wave arrives at an interface at anyincident angle other than 0 degrees (normal to the interface), some ofthe illuminating P energy converts into reflected and refracted P, andsome converts into reflected and refracted SV. Thus P-to-SV conversionoccurs at interface coordinates remote from a source, not directly atthe source point. A converted SV mode requires two conditions bepresent: 1) an interface across which there is a contrast in acousticimpedance, and 2) a P-wave raypath arriving at that interface at anangle that is not normal to the interface. When the incident angle is 0degrees (raypath perpendicular to the interface), the P-to-SV reflectioncoefficient is zero. At other incident angles, the P-SV reflectioncoefficient is non-zero.

Referring to FIG. 12, charts 1200, 1202 and 1204 illustrate actual X, Y,Z data acquired at the Devine Test Site with the vertical receiver arraywhen a shot-hole explosive source was positioned at source station 5,offset 1250 ft from the array. Charts 1206, 1208 and 1210 illustrate thesame data rotated to P, SV, SH data space. No P or SV events appear onthe SH data panel. SV events appearing on the P data panel are weakerthan is the case for a vertical-impact source, perhaps due to moreaccurate receiver rotations. Note at shallow take-off angles (top 4 or 5receiver stations), SH waves travel faster than SV waves as predicted byLevin (1979, 1980), supra, and measured by Roberson and Corrigan (1983),supra.

Referring to FIG. 13, charts 1300, 1302 and 1304 illustrate actual X, Y,Z data acquired at the Devine Test Site with the vertical receiver arraywhen a vertical-vibrator source was positioned at source station 6,offset 1500 ft from the array. Charts 1206, 1208 and 1210 illustrate thesame data rotated to P, SV, SH data space. No P or SV events appear onthe SH data panel. Measurements made at shallow take-off angles havelarger amplitudes than measurements made with vertical-impact andexplosive sources (FIGS. 11 and 12).

A constant plot gain is applied to each data panel on each of FIGS.11-13. Thus, within individual figures, P, SV, and SH amplitudes can becompared visually to judge relative energy levels of P and S modes. Suchcomparisons confirm SV and SH modes radiating away from a vertical-forcesource have amplitudes greater than the associated P mode. Data-displaygains differ for each source, so P and S amplitudes produced byexplosives should not be visually compared with P and S amplitudesproduced by vertical-impact or vertical-vibrator sources.

According to theory, SH data do not convert to either P or SV modes asan elastic wavefield propagates through a layered Earth, and conversely,P and SV modes do not convert to SH modes. No SH data panel contains Por SV events, which indicate the wavefield separations displayed onFIGS. 11 through 13 are properly done. Theory also establishes energy isfreely exchanged between P and SV modes as they propagate throughlayered media. All SV data panels on FIGS. 11-13 show P-to-SV conversionevents 1114, 1214, and 1314, which again indicate correct wave physics.Although minor amounts of SV energy remain on the P data panels, weconsider our wave-mode separation to be sufficiently accurate toestablish the fundamental principle that both SH and SV shear modes areproduced by a vertical-force source in addition to the expected P-wavemode.

Another piece of evidence confirming the two S modes shown on FIGS. 11to 13 are SV and SH is the fact the wavefront labeled SH travels fasterat shallow (near horizontal) takeoff angles than does the wavefrontlabeled SV. This distinction in SH and SV velocity behavior isemphasized by the theory documented by Levin (FIG. 4). The differencesin SH and SV velocities is best seen by comparing the arrival times of Swavefronts on FIGS. 11 and 12 at shallow receivers positioned over thedepth interval 500 to 700 ft.

Data Processing

There is a difference between S-wave source displacement vectorsproduced by vertical-force sources and conventional horizontal-forcesources. The S-wave displacement applied to the Earth by ahorizontal-force source is shown on FIG. 3. That displacement isoriented in a fixed azimuth direction (e.g., indicated by arrow 306),and Earth displacements around the point of application all point in thesame direction (e.g., as indicated by arrows 308) as the direction ofthe applied force. In contrast, the S displacement created by avertical-force source points in every azimuth direction around its pointof application, and the corresponding Earth displacement vectorslikewise point in all azimuth directions away from the source station(see FIG. 6). The effect seen in seismic reflection data is that S-wavedata produced by a dipole source (FIG. 3) have the same polarity inevery azimuth quadrant surrounding a source station, but S-wave dataproduced by a vertical-force source have different polarities whenviewed in azimuth directions that differ by 180 degrees.

S-wave data-processing strategies across the seismic industry are basedon the assumption that data polarities are constant across the entiretyof seismic image space. Thus the polarities of S-wave data acquired witha vertical-force source can be adjusted to look like constant-polaritydata produced by a dipole source via a data-polarity adjustment.

Referring to FIG. 14, a process of data-polarity adjustment will bedescribed. FIG. 14 shows a map view of a vertical-force source stationVFS positioned in a 3D seismic data-acquisition grid 1400. In seismicparlance, the direction receiver lines are deployed is called “inline,”and the direction source lines are oriented is called “crossline.” Inmost 3D seismic data-acquisition designs, inline and crosslinedirections are perpendicular to each other.

The azimuth direction of positive polarity in crossline and inlinedirections is arbitrary. However, once a data processor selects certaininline and crossline directions as being positive polarities, he/she hasautomatically divided inline and crossline seismic image space around avertical-force source station into two polarity domains—apositive-polarity domain and a negative-polarity domain. FIG. 14illustrates the principle of data-polarity reversals applied tovertical-force source data to create constant-polarity S-wave dataacross seismic image space. An exemplary 3D seismic data-acquisitiongeometry called orthogonal geometry is shown in which source line andreceiver lines are orthogonal to each other. VFS is a vertical-forcestation on one source line. A positive-polarity direction is selected(arbitrarily) for both the crossline (source line) direction and theinline (receiver line) direction. This decision divides seismic imagespace into two domains—a positive-polarity domain and anegative-polarity domain.

A real-data example of this data-polarity principle is illustrated inFIGS. 15 and 16. These 3D seismic data were acquired using a verticalvibrator. The data-acquisition grid is shown between each pair of datapanels to define the position of a fixed source station and variousreceiver stations where data produced by this vertical-force source wererecorded. The positive inline (IL) and crossline (XL) directionsassigned to the grid are indicated at each receiver station. The wiggletrace displays on the left show the polarities of the recorded data.Wiggle trace displays on the right show the data after polarityreversals have been applied as described in FIG. 14. After thesepolarity flips, all data have consistent polarity across the entirety ofseismic image space and can be processed by standard seismic software.

The data processing for SV and SH wave modes produced directly at thepoint of application of a vertical-force source differs from that ofprocessing converted-SV data. With direct-source data, data polaritiesare reversed in the negative-offset domain, and once this data-polaritycorrection is done, data in the two offset domains are processed as asingle data set, not as two separate data sets. Direct-source S-wavedata can be processed with common-midpoint (CMP) strategies; whereas,P-SV data are processed with common-conversion-point (CCP) strategies.Velocity analyses of data are done differently in these twodata-processing domains—common midpoint versus common conversion point.

FIG. 15 illustrates a first example of polarities of vertical-forceseismic data recorded in azimuth directions that differ by 180 degreesaway from a source station (left). On the right, FIG. 15 illustrates theresult of reversing polarities in the negative-polarity domain toconvert vertical-force source data to constant-polarity dipole-sourcedata.

FIG. 16 illustrates a second example of polarities of vertical-forceseismic data recorded in azimuth directions that differ by 180 degreesaway from a source station (left). On the right, FIG. 16 illustrates theresult of reversing polarities in the negative-polarity domain toconvert vertical-force source data to constant-polarity dipole-sourcedata.

Although vertical-force source data do not produce the same S-wave datapolarities as conventional horizontal-force sources, data polarityreversals, corrections, inversions or adjustments in appropriateportions of seismic image space transform vertical-force polarities tohorizontal-force polarities. After these polarity adjustments,vertical-force source data can be processed just as horizontal-forcesource data are, using known algorithms.

Findings

The EGL test data show that vertical-force sources, commonly perceivedas P-wave sources, generate more S energy directly at the forceapplication point than they do P energy. In one embodiment, the S energyis generated directly at the force application point of the source,rather than through applications of P-to-SV mode conversions atsub-surface interfaces.

In addition, field tests show vertical-force sources produce ahigh-energy, high-quality SH mode directly at the source station inaddition to an SV mode. This statement is confirmed by:

-   -   The mode claimed to be SH produces an Earth displacement normal        to the SV mode, and    -   Has a velocity greater than the SV mode at shallow takeoff        angles.

Thus, the EGL source test program evidences that full-elastic-wavefielddata (P, SV, SH) can be acquired using vertical-force sources.

The existence of SV mode data directly at the source station can becontrasted with SV data which is converted at impedance-contrastinterfaces in the Earth from P to SV mode by some layers of media belowthe Earth's surface, which can be referred to as “near the source.”There are only two ways to generate an SV shear mode: 1) use a sourcethat produces an SV displacement directly at the source station, or 2)use a source that generates a robust P wave and utilize the converted SVmodes that P wave produces when it illuminates an interface at anyincident angle other than 0 degrees.

As explained above, SH data are observed in data produced by the threegeneral types of vertical-force sources (vertical vibrator, verticalimpact, shot hole explosive), which means an SH displacement occursdirectly at the point where a vertical-force source applies its forcevector to the Earth.

Data Acquisition and Processing

Referring now to FIG. 17, a diagram of a data acquisition and processingsystem 1700 and method for acquiring and processing full elasticwaveform data from a vertical-force source using surface-based sensorswill be described. A vertical-force seismic source 1702 is disposed on,near, or within a shallow recess of the Earth's surface 1704. Source1702 is configured to impart a vertical-force to surface 1704 to provideseismic waves into Earth media 1706. Source 1702 may comprise a verticalvibrator, shot-hole explosive, vertical-impactor, air gun, verticalweight-dropper or thumper, and/or other vertical-force sources. In thisexample, vertical-force source 1702 produces compressional P mode andboth fundamental shear modes (SH and SV) in Earth 1706 directly at apoint of application 1708 of the vertical-force source. In thisembodiment, at least some of the SH and SV shear waves are generated atsource 1702 and not by subsurface conversion caused by portions of Earthmedia 1706. The frequency waves may be provided in a frequency sweep ora single broadband impulse. A vertical-force source may be used withoutany horizontal-force sources.

A seismic sensor 1710 is along the Earth's surface, which may includebeing disposed on, near, or within a recess of the Earth's surface 1704.For example, in one embodiment, shallow holes may be drilled and sensors1710 deployed in the holes to avoid wind noise, noise produced by rainshowers, etc. Sensor 1710 is configured to detect or sense upgoing wavemodes, reflected from subsurface sectors, formations, targets ofinterest, etc. In this embodiment, sensor 1710 comprises amulti-component geophone, for example a three-component geophoneconfigured to sense compressional P mode and both fundamental shearmodes (SH and SV). As described in FIGS. 1-14, various arrays andconfigurations of sources 1702 and sensors 1710 may be implemented indifferent embodiments. For example, two-dimensional or three-dimensionalacquisition templates may be deployed across Earth's surface 1704. Asanother example, a plurality of sources 1702 (e.g., at least two, atleast five, at least ten, etc.) may be disposed along a line and beconfigured to transmit seismic waves together or simultaneously.Vertical seismic profiling may be used in one embodiment. In analternative embodiment, a reverse vertical seismic profiling arrangementmay be used, in which one or more sources is disposed in a hole or welland one or more 3-component sensors or receivers are disposed along theEarth's surface. In another alternative embodiment, an interwellarrangement may be used, in which sources are disposed in one well orhole and 3-component receivers or sensors are disposed in another wellor hole. An in-hole source may be a wall-locked mechanical vibrator inan air-filled or fluid-filled well, or an air gun, water gun, orhigh-energy piezo-ceramic transducer freely suspended in a fluid column,or other source.

A seismic recording system 1712 is configured to receive seismic datasensed by sensor(s) 1710 via a wired or wireless communication link andto store the data in a database. System 1712 may comprise any type ofcomputing device. System 1712 may be configured to acquire and/orprocess the received data. For example, processing may comprisepolarity-reversal as previously described, the processing steps of FIG.18 below, or other seismic data processing algorithms.

A digital media output device 1714 may be coupled to system 1712, ordata may be transferred to device 1714 from system 1712 using any of avariety of technologies, such as a wired or wireless network, memorydevice, etc. Device 1714 may comprise one or more of a display device, aprinter, a speaker, and/or other output devices.

According to one embodiment, system 1712 can be configured to acquire orcapture SH-SH mode data with surface-based sensors. According to anotherembodiment, system 1712 can be configured to acquire both SV and SH modedata with surface-based sensors.

Referring now to FIG. 18, a diagram of a data acquisition and processingsystem 1800 and method for acquiring and processing full elasticwaveform data from a vertical-force source using sub-surface sensorswill be described. A vertical-force seismic source 1802 is disposed on,near, or within a shallow recess of the Earth's surface 1804. Source1802 is configured to impart a vertical-force to surface 1804 to provideseismic waves into Earth media 1806. In this example, vertical-forcesource 1802 produces compressional P mode and both fundamental shearmodes (SH and SV) in Earth 1806 directly at a point of application 1808of the vertical-force source. In this embodiment, at least some of theSH and SV shear waves are generated at source 1802 and not by subsurfaceconversion caused by portions of Earth media 1806. Contamination of Sdata produced directly at a source station by converted-SV data producedat interfaces remote from the source station may occur. A dataprocessing system may be configured to resolve, remove, reduce oridentify this converted-SV data (and/or other noise modes, such as Pevents, P and S multiples, reverberating surface waves, wind noise,etc.) and to emphasize, amplify, or identify the target signal.

A plurality of seismic sensors 1810 are disposed at a plurality oflocations within each of one or more shallow or deep holes drilled atany deviation angle. Sensors 1810 may be deployed permanently (e.g., bycementing or otherwise securing them in place) or they may beretrievable via wireline or coil tubing. Sensors 1810 are configured todetect or sense upgoing wave modes, reflected from subsurface sectors,formations, targets of interest, etc. In this embodiment, sensors 1810each comprise at least one multi-component geophone, for example athree-component geophone configured to sense compressional P mode andboth fundamental shear modes (SH and SV). As described in FIGS. 1-14,various arrays and configurations of sources 1802 and sensors 1812 maybe implemented in different embodiments.

Sensor deployment equipment and seismic recording system 1812 may beconfigured to position sensors 1810 within hole 1809, provide power tosensors 1810, and provide other functions needed to deploy sensors 1810.System 1812 comprises a computing system configured to receive seismicdata sensed by sensors 1810 via a wired or wireless communication link1813 and to store the data in a database. System 1812 may be configuredto acquire and/or process the received data. For example, processing maycomprise polarity-reversal as previously described, the processing stepsof FIG. 18 below, or other seismic data processing algorithms.

A digital media 1815 may be coupled to system 1812 using any of avariety of technologies, such as a wired or wireless network, etc. Media1815 may be configured to store and transfer the sensed and/or processedto data to other computing devices.

Referring now to FIG. 19, a data processing system for processing fullelastic wavefield data will be described. System 1900 comprises adigital computation system 1902, such as a personal computer, UNIXserver, single workstation, high-end cluster of workstations, or othercomputing system or systems. System 1902 comprises sufficient processingpower to process large quantities of complex seismic data. A massstorage device 1904 or other memory is coupled to digital computationsystem 1902, which is configured to receive data from the fieldrecorders or sensors stored on a digital media 1906, such as a memorycard, hard drive, or other memory device. Mass storage device 1904 isconfigured to download or receive the multi-component seismic data fromdigital media 1906 and to store the data in a database.

A user interface 1908, such as a keyboard, display, touch screendisplay, speaker, microphone, and/or other user interface devices may becoupled to system 1902 for two-way communication between system 1902 anda user. According to one exemplary embodiment, multiple user terminals1910 may access data processing system 1902 through a user interfaceusing a network of computers, terminals, or other input/output devices(e.g., a wide-area network such as the Internet).

A software library 1912 is coupled to data processing system 1902 andcomprises one or more non-transitory computer-readable media programmedto perform one or more processing algorithms. The processing algorithmsmay comprise any of a number of known seismic data processing algorithmsor algorithms described herein or which may be developed in the future.The algorithms can comprise algorithms in two categories: (1) algorithmsrequired to process data acquired by surface-based 3-component sensors,and (2) algorithms required to process data acquired with 3-componentsensors positioned in deep wells.

Surface-Based Sensors

For surface-based sensors, data computation system 1902 may beprogrammed with existing code, both proprietary code and publiccommercial code. System 1902 may be programmed with new code to optimizedata handling and image construction. System 1902 may be programmed toextract P, SH, and SV modes from recorded data, as described herein withreference to FIGS. 1-14.

Deep Well Sensors

When data are acquired with sensors in deep wells, the procedure iscalled vertical seismic profiling (VSP). VSP data-processing systems arenot as widely distributed as are systems for processing surface-sensordata. VSP data may be processed using data-processing systems made orused by VSP contractors, such as Schlumberger, Halliburton, Baker Atlas,READ, and/or other companies. The data processing systems may beconfigured to extract P, SH, and SV modes from recorded data, by lookingfor SV and SH radiating directly from a surface source station.

System 1900 may further comprise one or more output devices 1914 coupledto digital computation system 1902. Output devices 1914 may compriseplotters, tape drives, disc drives, etc. configured to receive, store,display and/or present processed data in a useful format.

Referring now to FIG. 20, a flow diagram illustrating a method 2000 ofprocessing full elastic wave data will be described. The method may beoperable on one or more processing circuits, such as digital computationsystem 2002. At a block 2002, a processing circuit is provided withmixed P, SH and SV modes in field-coordinate data space (inline andcrossline) from acquisition steps described previously. At block 2004,the processing circuit is configured to or programmed to segregate,separate or otherwise remove P mode data by applying velocity filters toreject or filter out SH and SV modes.

A velocity filter is any numerical procedure applied to seismic datathat emphasizes events that propagate with a certain targeted velocitybehavior and attenuates events that propagate with velocities differentfrom this targeted velocity. There are numerous algorithms available toseismic data processors that perform velocity filtering. Some of thesefilters operate in the frequency-wavenumber (f-k) domain, some in thetime-slowness (tau,p) domain, some are median filters in the time-depthdomain, etc. Velocity filters allow primary P reflections to besegregated from P multiples, and S events to be isolated from P events.

Converted SV events have a faster velocity than do direct-S eventsbecause a converted SV involves a downgoing P wave; whereas, thedowngoing raypath for a direct-S event is S (much slower than P).Velocity filters can be designed that pass the slow velocitiesassociated with an S-S event (downgoing S and upgoing S) and reject thefaster velocities of P-SV events (downgoing P and upgoing SV).

At a block 2006, the processing circuit is configured to reversepolarities of inline and crossline horizontal-sensor data acquired atnegative offsets, as described above with reference to FIGS. 10-14. At ablock 2008, the processing circuit is configured to transform horizontalsensor data from inline/crossline data space to radial/transverse dataspace, as described above with reference to FIGS. 10-14. As a result,the SH and SV modes (SH=transverse data; SV=radial data) are segregatedand processed separately. The order of blocks of method 2000 may berearranged in various embodiments; for example, the order of blocks 2006and 2008 can be exchanged.

At a block 2010, radial sensor data are set aside as an SV data base,and transverse sensor data are set aside as an SH data base. Thissegregation of SV and SH modes allows the modes to be individuallyintroduced (e.g., as separate data sets) into the data-processing streamstarting at block 2012.

At a block 2012, any one of numerous velocity analysis proceduresavailable in the seismic data-processing industry may be applied to eachwave mode, P, SV, and SH, separately. Popular velocity-analysis optionsare semblance stacking, frequency-wavenumber analysis, and time-slownessanalysis. This step identifies an optimal velocity function for eachwave mode that will emphasize primary reflection events for that wavemode and attenuate noise, interbed multiples, and spurious events fromcompeting wave modes.

At a block 2014, static corrections are applied to improve reflectoralignment. These corrections involve time shifts of data acquired ateach source and receiver station. Because these time shifts are appliedto an entire data trace, they are termed static corrections todifferentiate them from dynamic time adjustments done by otherprocesses. One static correction removes timing differences caused byvariations in station elevations by adjusting time-zero on each datatrace to mathematically move all source and receiver stations to acommon datum plane. A second static correction removes timingdifferences cause by different velocities being local to differentsource and receiver stations. The end result of these static correctionsis an improvement in reflection continuity.

At a block 2016, any one of many noise rejection procedures may beapplied to the data to improve the signal-to-noise ratio. Some noiserejection options may be simple frequency filters. Others may be moresophisticated tau-p, f-k, or deconvolution procedures.

At a block 2018, the data are stacked (or summed) to create an initialimage. Embedded in this step is a dynamic time adjustment of reflectionevents called a moveout correction that is applied to flatten reflectionevents to the same time coordinate at all source-receiver offsets. Adata-acquisition geometry may cause many source-receiver pairs toproduce reflection events at the same subsurface coordinate. Instacking, the flattened reflections from all source-receiver pairs thatimage the same subsurface coordinate are summed to make a single imagetrace at that image-space coordinate. When this stacking process isextended across the entire seismic image space, a single image tracewith high signal-to-noise character is produced at each image point inthe image space. It is at this step that a data processor gets his/herfirst look at the quality of the velocity analysis and staticcorrections that have been applied to the data (e.g., by displaying thedata on an electronic display, printing the data using a printer, etc.).

At a block 2020, the data processor has to decide if the image issatisfactory or if the data processing should be repeated to improve theaccuracy of the velocity analyses that perform the dynamic moveoutcorrections of reflection events and to improve the accuracies of thestatic corrections that time shift reflection events at each source andreceiver station. If the decision is to repeat the imaging process, theprocedure returns to block 2012 and proceeds to block 2020 again. If theEarth consists of flat horizontal layers, these stacked data are a goodimage of the subsurface geology. If Earth layers are dipping or faulted,these stacked data are not a true image of the geology, but they stillindicate the quality of the true image that will be created when thedata are migrated (Block 2022).

At a block 2022, the data are migrated. Migration is a procedure thatutilizes a seismic-derived velocity model of the Earth to movereflection events from their coordinate positions in offset-vs-timeimage space to their correct subsurface positions in the Earth. Numerousmigration algorithms are available in the seismic data-processingindustry. Some algorithms are proprietary to data-processing companies;others are available as commercially leased software or as sharedfreeware.

The position of the data migration step on FIG. 20 is a post-stackmigration procedure. The migration step can be moved to be positionedbetween blocks 2016 and 2018 to do pre-stack migration. Pre-stackmigration is often more desirable than post-stack migration but is morecomputer intensive. Pre-stack time migration and depth migration allowthe vertical coordinate axis of the image to be either depth or time,depending on the data processor preference. The possibility of imagingusing reverse time migration techniques can be utilized at this point ifdesired.

The teachings herein may be implemented by seismic contractors, oil andgas companies, and others. The teachings herein may be used in otherindustries as well, such as geothermal energy, CO2 sequestration, etc.

Extant Data

The systems and methods described herein may be applied to processing ofextant or pre-existing or legacy sets of seismic data. According to oneexample, a memory comprises seismic data which may be raw, unprocessedor partially processed. The seismic data may have been generated monthsor years prior to the processing of the data. A processing circuit maybe configured to process the seismic data to generate, provide, orachieve full elastic waveform data. For example, the processing circuitmay be configured to reverse polarities of horizontal sensor dataacquired at negative offsets as described herein to generate S modedata, such as SH mode and SV mode data. The processing circuit mayfurther be configured to extract P, SH, and SV modes from the previouslyrecorded data. In one embodiment, the seismic sensors will have beenreceiving data for a sufficient period of time, such as at least tenseconds or at least twelve seconds, in order to receive all of theslower-moving SH and SV modes in addition to the P mode data.

According to one embodiment, sources other than explosive sources (i.e.non-explosive sources, such as vertical vibrators and vertical-impactsources) may be used to construct S-mode images, such as SV and SHimages. The advantages of non-explosive sources include that they areacceptable sources in environments where explosive sources areprohibited or impractical. Exemplary advantages include:

-   -   Explosives cannot be used in urban environments. In contrast,        vibrators can operate down streets, alleys, and in close        proximity to buildings.    -   Explosives cannot be used along road right-of-ways. County roads        and public highways are popular profile locations for vibrators.    -   In areas contaminated by mechanical noise (road traffic,        gas-line pumping stations, oil well pump jacks, active drilling        rigs, etc.), the compact impulsive wavelet (typically spanning        only 100 to 200 ms) produced by an explosive shot can be        overwhelmed by short noise bursts from noise sources local to        one or more receiver stations. In contrast, a vibrator creates a        wavelet by inserting a long (10 to 12 seconds) chirp into the        Earth in which frequencies vary with a known time dependence.        Unless mechanical noise has exactly the same frequency variation        over a 10-second or 12-second time duration as does a vibrator        chirp signal, the cross correlation procedure used to identify        vibroseis reflection events suppresses the noise. Explosive        sources are less practical than vibrators in high-noise        environments.    -   Vertical impact sources have appeal because they are lower cost        than explosive sources (and usually lower cost than vibrators).        Operators often choose the lowest cost source even if the source        has some technical shortcomings.

While non-explosive sources are used in some embodiments describedherein, explosive sources may be used in other embodiments describedherein.

S data can be acquired in the widest possible range of environments whenvertical-force sources are utilized. Explosive sources can be used inswamps, mountains, etc. where non-explosive sources are not feasible orpractical, and vibrators and vertical impact sources can be used inhigh-culture areas (cities, roads, etc) where explosives are prohibited,and when budget constraints limit source options.

The systems and methods described with reference to FIGS. 17-20 mayimplement any of the features or principles described with reference toFIGS. 1-16.

Extracting SV Shear Data from P-Wave Seismic Data

Referring now to FIGS. 21-35, system and methods for extracting SVshear-wave data from P-wave seismic data will be described.

Systems and methods are described for extracting SV shear-wave data fromP-wave seismic data acquired with a vertical-force source and verticalgeophones. The P-wave seismic data may comprise legacy P-wave data(e.g., P-wave data acquired at some time days, months, or years, such asat least one year, in the past), P-wave data acquired in the presentday, two dimensional data, three dimensional data, single-componentsensor data, and/or three-component sensor data acquired across a widevariety of Earth surface conditions.

These systems and methods are based on the use and application of theSV-P mode produced by a vertical-force seismic source. The SV componentof this seismic mode provides valuable rock and fluid information thatcannot be extracted from P-wave seismic data. The systems and methodsmay produce an S-wave image from seismic data acquired withsurface-based vertical geophones.

According to some embodiments, vertical, single-component orone-component, surface-based seismic sensors are used to acquire SVshear data. In some embodiments, only a vertical, single-componentreceiver may be present (or have been present in the case of legacydata) at each receiver station.

Systems and methods are described for extracting SV-SV data from P-waveseismic data acquired with a vertical-force source and verticalgeophones in situations where P-wave data are acquired across areas ofexposed high-velocity rocks.

Systems and methods are described for extracting P-SV data from P-waveseismic data acquired with a vertical-force source and verticalgeophones in situations where P-wave data are acquired across areas ofexposed high-velocity rocks.

In some embodiments, there is no requirement of any specific positioningof receiver relative to source. In some embodiments, the systems andmethods described herein may apply whether source and receiver are bothon the Earth surface, at the same elevation, or at distinctly differentelevations.

In some embodiments, upgoing SV events are not used in imaging; instead,only the upgoing P part of SV-P data are used in imaging.

In some embodiments, the sources may have known or predeterminedlocations relative to surface-based receivers and the direction oftravel of energy that reaches the receivers at their receiver stationsmay be known before processing of the received data.

The principal seismic reflection data that are acquired to evaluategeological conditions across onshore areas are compressional-wave(P-wave) data. From a historical perspective, numerous large librariesof legacy seismic data exist, with the ages of these data extending backinto the 1950's and 1960's. Most legacy seismic data are P-wave data.

The term “land-based” seismic data refers to any seismic data acquiredin non-marine environments, which would include data acquired acrossswamps, marshes, and shallow coastal water, as well as data acquiredacross exposed land surfaces. Land-based P-wave data are generated usingvertical-force sources. This term “vertical-force source” includes anyseismic source that applies a vertical force to the Earth. Included inthe broad range of vertical-force seismic sources are verticalvibrators, vertical impacts, and shot-hole explosives.

P-wave land-based seismic data are recorded using vertical geophones orother vertically oriented seismic sensors. When acquiring P-wave seismicdata, the sensor deployed at each receiver station can be eithersingle-component or three-component as long as sensor elements in eachreceiver package measure vertical movement of the Earth.

One or more embodiments described herein may allow SV shear-wave data tobe extracted from P-wave data acquired with vertical-force sources andvertical sensors. One or more embodiments may apply whether a sensorpackage is single-component or three-component. One or more embodimentsmay apply to legacy P-wave seismic data as well as to P-wave dataacquired in the present day.

One or more embodiments described herein may allow SV shear-wave data tobe extracted from either 2D or 3D P-wave data.

SV-to-P Seismic Mode

The embodiments that are configured to extract SV shear-wave data fromP-wave data use the SV-to-P converted seismic mode. The notation SV-Pwill be used to designate this wave mode. In this notation, the firstterm identifies the downgoing seismic wave (SV) that illuminatesgeologic targets, and the second term designates the upgoing reflectedwave (P) from those targets. To maintain consistent notation, standardP-wave data will be labeled as P-P data, meaning the downgoingilluminating wavefield is a P-wave, and the upgoing reflected wavefieldis also a P-wave.

Raypath diagrams comparing SV-P imaging of subsurface geology andconventional P-P imaging are illustrated on FIG. 21. The bold arrows2100, 2102 drawn at the source station 2104 and receiver station 2106are vertical to illustrate: (1) the seismic source applies a verticalforce vector to the Earth, and (2) each sensing geophone is orientedvertically or otherwise configured to sense or measure vertical movementof the Earth. Receiver 2102 may be a vertical geophone, a verticalcomponent of a multi-component geophone, or another single- ormulti-component geophone configured to sense, measure or detect verticalmovement of the Earth (e.g., a “54 degree” geometry geophone orGal'perin geophone). As described hereinabove, a vertical-force seismicsource produces not only P waves but also SV and SH shear waves.Consequently, both downgoing P and downgoing SV raypaths are shownpropagating away from the vertical-force source station 2104 on FIG. 21.Segments of downgoing and upgoing raypaths are labeled either P or SV toindicate the specific wave mode that travels along each segment of eachraypath. Circled arrows on each raypath segment identify the directionin which the wave mode acting on that raypath segment displaces theEarth. The data polarities indicated by these particle displacementvectors agree with the polarity conventions defined by Aki and Richards(1980).

“Common-midpoint” imaging may be used to produce P-P stacked images ofthe Earth's subsurface. In a flat-layered Earth, when the velocity ofthe downgoing wavefield that illuminates a geologic target is the sameas the velocity of the upgoing reflected wavefield from that target, asit is for P-P data, the reflection point (image point) is half waybetween the source and the receiver. Therefore, the terms “commonmidpoint” or “CMP” are used to describe this imaging concept.

When seismic images are made using a downgoing illuminating wavefieldthat has a velocity that differs from the velocity of the upgoingreflected wavefield, a different concept called“common-conversion-point” imaging is used to construct stacked images ofgeologic targets. The abbreviation “CCP” is used to indicate thisseismic imaging strategy. CCP imaging techniques are used to constructstacked images from SV-P data because the downgoing SV mode has avelocity that differs from the velocity of the upgoing P mode (FIG. 21).

As shown on FIG. 21, the upgoing events that arrive at a receiverstation are P-wave events for both P-P and SV-P modes. A concept notillustrated in this simplified, straight-raypath model is that a Praypath curves to become almost true-vertical when it enters anunconsolidated, low-velocity layer 2100 that covers most of the Earth'ssurface. This principle is illustrated on FIG. 22. When upgoing Praypaths 2200, 2202 bend to almost true-vertical as they approach areceiver station 2106, their particle displacement vectors 2204, 2206align with vertically oriented geophones at receiver station 2106 andinduce a strong response in a vertical geophone. Because both legacyP-wave seismic data and present-day P-wave data are recorded withvertical geophones, these P-wave data contain not only P-P modes, butalso SV-P modes, such as raypath 2200 illustrated in FIG. 22.

As illustrated in FIG. 36, if a P-wave is traveling in a true horizontaldirection when it arrives at a vertical geophone, the P-wave will notgenerate any response in the geophone. If a P-wave is traveling in atrue vertical direction when it arrives at a vertical geophone, theP-wave will induce a maximum geophone response (A). At any intermediateangle of approach, the geophone response produced by an arriving P-wavewill be A cos(Φ), where Φ is the approach angle measured relative totrue vertical, and A is the maximum response the P-wave produces when ittravels in a true vertical direction. At some non-vertical approachangle Φ_(x), a P-wave will still have a small vertical component thatwill produce a small response in a vertical geophone, but not a “usable”signal. The exact value of cutoff angle Φ_(x) varies from location tolocation, and varies day to day at any given location, depending on thelevel of background noise that is present. Background noise includeswind-generated shaking of local vegetation, mechanical vibrations fromnearby machinery or vehicular traffic, water drops falling from the skyor dripping from close-by trees and bushes, and other factors thatinduce disturbances close to a geophone station.

An additional imaging option is illustrated on FIG. 23. In thisscenario, the raypath labeling acknowledges a vertical-force source 2104causes an SV-SV mode 2300 which arrives at a receiver station 2106 justas does a P-P mode 2108 (FIG. 21). However, when the principle isapplied that, in most Earth surface conditions, raypaths approach asurface receiver in an almost or substantially vertical direction, theorientation of the particle displacement vector 2302 associated with anupgoing SV raypath 2301 does not activate a vertical geophone (as theupgoing P waves do in FIG. 22). Thus for some P-wave data acquired withvertical geophones, it may not be possible to extract SV-SV reflectionevents (or P-SV reflection events) from the response ofvertical-geophone data.

An exception to the principle described on FIG. 23 occurs when verticalgeophones are deployed across an Earth surface where the top Earth layeris a hard, high-velocity material, as in layer 2400 in FIG. 24. In thistype of surface condition, an SV raypath 2400 will arrive at a receiverstation 2106 along a substantially nonvertical trajectory, and thevertical component of an SV particle displacement vector 2402 willactivate a vertical geophone 2106 (FIG. 24). Thus, when P-wave data areacquired across high-velocity surfaces with vertical geophones, datahaving an upgoing SV mode are recorded by vertical geophones in additionto SV-P data. As a result, both P-SV and SV-SV data, which both haveupgoing SV modes, are recorded by vertical geophones in situations wheregeophones are deployed across a high-velocity surface layer. Bothupgoing P and SV raypaths in FIG. 24 approach receiver station 2106 froma direction that differs significantly from near-vertical.

As illustrated in FIG. 37, where the upgoing mode is SV, the responsethat an SV arrival induces in a vertical geophone is A sin(Φ), ratherthan A cos(Φ) as it is for an upgoing P mode. The larger Φ is, thestronger the SV response is. As S velocity increases in the top-mostEarth layer, Φ increases. How big Φ should be, and how large S velocityshould be to ensure there is an appreciable value of Φ, depend again onthe magnitude of the background noise at the receiver station.

One or more embodiments described herein may acquire P-SV data withoutthe use of three-component geophones and without extracting the upgoingSV mode from horizontal-geophone responses. One or more embodimentsdescribed herein allows P-SV data to be acquired with single-componentvertical geophones, for example in situations where the top Earth layeris high-velocity rock. One or more embodiments described herein mayacquire P-SV data without the use of a receiver configured to sense,detect or measure horizontal movement of the Earth.

P-SV and SV-P raypaths are compared on FIG. 25. Because upgoing raypathsbecome near-vertical in a low-velocity surface layer (FIG. 22), theorientation of particle displacement associated with the upgoing SVsegment 2500 of a P-SV mode 2502 fails to activate a vertical geophonein many Earth surface environments. Thus, in some vertical-geophoneP-wave data, there will be no usable P-SV data. However, P-SV data willbe recorded by a vertical geophone in cases where the top Earth layerhas high velocity (FIG. 24).

SV-P Image Space

The imaging principles of P-SV and SV-P modes 2502, 2504 illustrated onFIG. 25 emphasize an SV-P mode images geology 2506 closer to a sourcestation 2508 than to a receiver station 2510. When P-wave data areacquired with a source-receiver geometry in which receivers occupy anarea that differs significantly from the area occupied by sources, it isuseful to understand how the image space spanned by SV-P data differsfrom the image space spanned by the P-SV mode.

FIGS. 26A and 26B show two options in which P-wave data are acquiredacross the same image space using vertical-force sources and verticalgeophones. The figures illustrate source-receiver geometries from anaerial view looking downward, showing the size and position of SV-Pimage space (I1, I2, I3, I4) for two three-dimensional P-wavedata-acquisition geometries. With the source-receiver geometry shown onFIG. 26A, the area spanned by source stations 2600 is larger than thearea spanned by receiver stations 2602. In the option shown as FIG. 26B,the reverse is true, and receivers span an area 2604 larger than thearea spanned by sources 2610. The CMP P-wave image space will be thesame for both geometries because the same number of source-receiverpairs is involved, and these station pairs occupy the same Earthcoordinates in both geometries. To avoid graphic clutter, the boundariesof P-P image space are not shown on the drawings, but if drawn, theboundaries of P-P image space would be half-way between the boundariesof receiver area R1-to-R4 and the boundaries of source area S1-to-S4 inboth FIGS. 26A and 26B, reflecting the midpoint aspect of the CMPmethod.

The size and position of SV-P image space resulting from these twodistinct data-acquisition geometries of FIGS. 26A and 26B differ. SV-Pimage space covers a large area 2608 when the geometry option of FIG.26A is used and a relatively smaller area 2606 when the geometry optionof FIG. 26B is used. For both geometries, SV-P image points arepositioned closer to source stations than to receiver stations. Becauseof the reciprocal relationships between the image coordinates of SV-Pand P-SV modes (FIG. 25), the image space spanned by P-SV data when thegeometry of FIG. 26A is used would be the image space spanned by SV-Pdata in FIG. 26B. If the geometry of FIG. 26B is used, then P-SV datawould span the SV-P image space drawn on FIG. 26A. Because the samenumber of source-receiver pairs is involved in each data-acquisitiongeometry in this exemplary embodiment, SV-P stacking fold across thelarger area (FIG. 26A) will be lower than SV-P stacking fold across thesmaller area (FIG. 26B). Each geometry offers advantages for the SV-Pmode, depending on the signal-to-noise ratio of SV-P data. If the SV-Psignal-to-noise ratio is rather high, then the option of FIG. 26Aextends good-quality SV information over a larger area than what isimaged by P-SV data. If the SV-P signal-to-noise ratio is low, thenincreasing SV-P fold over a smaller area as in FIG. 26B should createbetter quality SV information than what is provided by P-SV data thatextend over a larger area with reduced fold.

SV-P Data Processing—Data Polarity

As explained with reference to the embodiments of FIGS. 1-20, to extractSV-SV and SH-SH modes from data generated by a vertical-force source,the processing reverses the polarity of data acquired by horizontalgeophones stationed in the negative-offset direction relative to thepolarity of data acquired by horizontal geophones deployed in thepositive-offset direction. That data polarity adjustment does not applyto SV-P data in this embodiment because the SV-P wave mode is recordedby vertical geophones, not by horizontal geophones.

Raypaths involved in positive-offset and negative-offset SV-P imagingare illustrated on FIG. 27. In this diagram, SV-P data generated atvertical source A and recorded at vertical receiver A are labeled SV_(A)for the downgoing SV mode and P_(A) for the upgoing P mode. The offsetdirection from vertical source A to vertical receiver A is arbitrarilydefined as positive offset. When the positions of source and receiverare exchanged, creating vertical source B and vertical receiver B, theoffset direction reverses and is defined as negative offset. The raypathfor negative-offset SV-P data is labeled SV_(B) for the downgoing SVmode and P_(B) for the upgoing P mode. The polarities shown for thedowngoing SV particle-displacement vector conform to the polarityconvention established by Aki and Richards (1980) and documented byHardage et al. (2011). Note that for both positive-offset data andnegative-offset data, the vertical component of theparticle-displacement vectors for the upgoing P modes are in the samedirection (pointing up), hence there is no change in SV-P data polaritybetween positive-offset data and negative-offset data.

If the SV-SV mode is extracted from P-wave data in situations where ahigh-velocity Earth surface allows the upward traveling SV mode toenergize a vertical geophone (FIG. 24), it likewise is not necessary toadjust the polarity of the vertical-geophone data in eitheroffset-direction domain. Adjusting the polarity of upward traveling SVmodes in the negative-offset domain to agree with the polarity in thepositive-offset domain is used when the SV mode is recorded byhorizontal geophones, not when they are acquired by vertical geophones.

SV-P Data Processing—Velocity Analysis

The embodiments described herein may be configured to perform a velocityanalysis as a data-processing step when constructing seismic images.When CMP data are processed, it is not necessary to be concerned aboutwhich offset domain (positive or negative) data reside in whenperforming velocity analyses. If the velocities of downgoing and upgoingwave modes are the same (CMP data processing), the same velocitybehavior occurs in both offset directions. However, when converted modesare involved, the method may comprise two velocity analyses—one analysisfor positive-offset data and a second analysis for negative-offset data.

The reason for this dual-domain velocity analysis is illustrated on FIG.27, which shows two distinct rock facies between two surface-basedsource and receiver stations. Laterally varying rock conditions such asshown on this diagram can be found in many areas. For purposes ofillustration, assume the P and S velocities in Facies A aresignificantly different from the P and S velocities in Facies B. Thetravel time required for a positive-offset SV-P event to travel raypathSV_(A)-P_(A) is not the same as the travel time for a negative-offsetSV-P event to travel raypath SV_(B)-P_(B). This difference in traveltime occurs because the SV_(A) mode is totally in Facies A, but theSV_(B) mode is almost entirely in Facies B. Likewise, all of mode P_(B)is in Facies A, but mode P_(A) has significant travel paths insideFacies A and Facies B. Because travel times differ in positive-offsetand negative-offset directions, one velocity analysis is done onpositive-offset data, and a separate velocity analysis is done fornegative-offset data.

Examples of SV-P reflection events extracted from P-wave data byvelocity analysis are displayed as FIGS. 28A and 28B. FIGS. 28A and 28Billustrate SV-P reflections extracted from vertical-geophone P-waveseismic data. The seismic source was a shot-hole explosive (avertical-force source). Two shot signal gathers or acquisitionsgenerated at source stations 1007 and 1107 are displayed after velocityfiltering. For each shot gather, velocity analyses were done separatelyfor positive-offset data and negative-offset data. In these examples,there is not a large difference between positive-offset andnegative-offset velocities. As a result, the curvatures ofnegative-offset SV-P reflections are approximately the same as thecurvatures of positive-offset SV-P reflections.

Only reflection events having curvatures coinciding with downgoing V_(S)velocities and upgoing V_(P) velocities appropriate for the rocksequence where these data were acquired are accepted. Other velocitiesare rejected. These examples come from a seismic survey for which theenergy sources were vertical-force sources, and the analyzed data wererecorded by vertical geophones. Analyses for two common-shot tracegathers are shown. For each shot gather, positive-offset data weresubjected to velocity analysis separately from negative-offset data.Each velocity analysis rejected reflection events having velocities thatdiffered by more than 20-percent from the velocities used to createhigh-quality P-SV images across the same image space. The result is thathigh-quality SV-P reflections are extracted from vertical geophone datafor both positive-offset P-wave data and negative-offset P-wave data.The principal difference in P-SV and SV-P velocity analyses in thisexemplary embodiment is that P-SV velocity analyses are done on datarecorded by horizontal geophones; whereas, SV-P velocity analyses aredone on data recorded by vertical geophones.

To make seismic images from the reflection events shown in FIGS. 28A and28B, reflection events for a number of source stations in the survey(e.g., at least 10, at least 100, at least 1000, etc.) would begenerated. The reflection event data then would be binned, stacked andmigrated. For example, the reflection event data may be binned using CCPor ACP binning strategies to define those coordinates. The reflectionevent data may then be stacked and then migrated after stack to generatean image. Migration physically moves reflections from where they are inreflection time to where they should be in image time.

The reflection events shown in FIGS. 28A and 28B comprise primaryreflection events and multiple reflection events. Multiple reflectionevents result from multiple reflections of seismic waves caused byreverberations between interfaces of layers of the Earth. Multiplereflection events can cause an image to not be positioned correctly intravel time space. Multiple reflections may be filtered out of thereflection events in subsequent processing.

The reflection events shown in FIGS. 28A and 28B comprise an interpretedprimary reflection at a point where reflection events in negative offsetand positive offset domains meet, such as point 2800. The reflectionevents comprise an interpreted multiple reflection at a point wherereflection events in negative offset and positive offset domains do notmeet, such as point 2802.

SV-P Data Processing: Constructing SV-P Images

The processing of SV-P data for generating images can be done in anumber of ways, such as: (1) by CCP binning and stacking of SV-Preflections, followed by post-stack migration of the stacked data, or(2) by implementing prestack time migration, depth migration orreverse-time migration of SV-P reflections. Each method has its ownbenefits. For example, method 2 (prestack migration) is a more rigorousapproach; method 1 (CCP binning/stacking and post-stack migration) islower cost. To perform CCP binning and migration of SV-P data, CCPcoordinates of SV-P image points are mirror images of CCP image pointsassociated with P-SV data, as illustrated on FIG. 29. The SV-Pdata-processing strategy may be based on this mirror-image symmetry ofCCP image-point profiles for P-SV and SV-P modes.

Because positive-offset and negative-offset SV-P data have differentvelocity behaviors, two separate CCP binning/stacking steps are done tocreate an SV-P stacked image. In a first step, positive-offset data arebinned and stacked into an image using velocities determined frompositive-offset data, and in a second step, negative-offset data arebinned and stacked into a second image using velocities determined fromnegative-offset data. The final SV-P image is the sum of these twoimages. This same dual-image strategy may be implemented when binningand stacking P-SV data. The three stacked images (negative-offset image,positive-offset image, and summed image) can be migrated and used ingeological applications. As documented by Hardage et al. (2011) relativeto P-SV imaging, some geologic features are sometimes better seen in oneof these three images than in its two companion images. Thus all threestacked and migrated images may be used in geological interpretations.

SV-P Data Processing: Method 1—CCP Binning, Stacking, and Post-StackMigration

Some commercial seismic data-processing software that can be purchasedor leased by the geophysical community can calculate converted-modeimage coordinates called asymptotic conversion points, which areabbreviated as ACP. Two examples are Vista seismic data processingsoftware, sold by Geophysical Exploration & Development Corporation,Alberta, Canada and ProMAX seismic data processing software, sold byHalliburton Company, Houston, Tex. An ACP is an image coordinate wherethe trend of correct CCP image points for a specific source-receiverpair becomes quasi-vertical (FIG. 29). Deep geology is correctly imagedusing P-SV data binned using ACP coordinates, and would also becorrectly imaged by SV-P data binned using ACP concepts that areadjusted for SV-P data. However, shallow geology is not correctly imagedfor either P-SV data or SV-P data when ACP binning methods are used.True CCP binning can produce correct stacked images of both shallow anddeep geology for converted modes appropriate for post-stack migration.On FIG. 29, the asymptotic conversion point for the P-SV mode is labeledACP1, and the asymptotic conversion point for the SV-P mode is labeledACP2. Neither image point is correct except where their associated CCPbinning profile is quasi-vertical (i.e., for deep targets). Asemphasized above, these two image points are mirror images of each otherrelative to the common midpoint (point CMP on FIG. 29) for anysource-receiver pair involved in a seismic survey.

One exemplary method of producing SV-P CCP/ACP binning comprisesadjusting software that performs CCP binning for P-SV data so that thecoordinates of sources and receivers are exchanged when determiningimage-point coordinates. Referring to the source-receiver pair drawn onFIG. 29, an exchange of station coordinates has the effect of moving thereceiver station to the source station and the source station to thereceiver station. Software used to process P-SV data will then calculatethe image point trend labeled CCP2 rather than the trend labeled CCP1.Using coordinates specified by profile CCP2 to bin SV-P reflectionsextracted from vertical-geophone data can produce SV-P images. The SV-Pimages should be equal in quality to what is now achieved with P-SVdata.

Curve CCP1 shows the trend of common-conversion points for P-SV data.Curve CCP2 shows the trend of common-conversion points for SV-P data.ACP1 and ACP2 are asymptotic conversion points for trends CCP1 and CCP2,respectively. CCP1 and CCP2 are mirror images of each other relative tothe common midpoint CMP for this source-receiver pair.

SV-P Data Processing: Method 2—Prestack Migration

According to an alternative embodiment, prestack migration can be doneso as to create a time-based seismic image or a depth-based seismicimage. Referring to FIG. 30, prestack migration may be done bynumerically propagating a specific seismic wavefield downward from eachsource station to illuminate geologic targets, and then numericallypropagating a specific seismic wavefield upward from reflectinginterfaces to each receiver station.

The specific wavefields used in prestack time migration, depthmigration, or reverse-time migration may be created by applying velocityfilters to data recorded by vertical geophones so that reflection eventshaving only a predetermined velocity behavior remain after velocityfiltering. The predetermined velocity behaviors of interest are thoseassociated with the following seismic modes: P-P, P-SV, SV-SV, and SV-P.If 3C geophones are used in combination with a vertical-force source, afifth velocity filtering option is to extract SH-SH reflection events.However, for this latter option, the filtering action is applied to datarecorded by transverse horizontal geophones. The result is an image ofgeologic interfaces seen by each specific seismic mode. For simplicity,only one source station and only one receiver station are shown on FIG.30.

The table on FIG. 30 considers only wave modes produced by avertical-force source as described hereinabove with reference to FIGS.1-20 (P, SV, SH) and the responses of only vertical geophones. For anEarth with isotropic velocity layers, there are five possiblecombinations of downgoing (D) and upgoing (U) modes. These possibilitiesare labeled Option 1 through Option 5 in the figure table.

As indicated by the table on FIG. 30, prestack migration software cancreate an SV-P image if the velocity of the downgoing wavefield is thatfor a propagating SV wavefield and the velocity of the upgoing wavefieldis that for a P wavefield. Examples of SV-P data that would be used forpre-stack migration Option 3 listed on FIG. 30 (SV-P imaging) areexhibited on FIG. 28. For a 3D P-wave seismic survey, velocity filteringsimilar to that done to produce these two example shot-gathers would bedone for all shot gathers across a survey area. If a survey involves1000 source stations, then 1000 velocity-filtered shot-gathers similarto those on FIG. 28 would be created. All 1000 sets of SV-P reflectionswould be pre-stack migrated downward through an Earth model havinglayers of SV velocities and then migrated upward through an Earth modelhaving layers of P-wave velocities.

In FIG. 30, a time-space distribution of velocities for a specificseismic mode is defined so that a specific downgoing wavefield (D) canbe propagated through this Earth velocity model from every sourcestation to illuminate targets. A second time-space distribution ofvelocities for a second specific seismic mode is then imposed topropagate that specific reflected upgoing wavefield (U) to everyreceiver station. The combinations of downgoing and upgoing velocitiesthat can be implemented for a vertical-force source and verticalgeophones are listed in the table of FIG. 30.

SV-P Data Processing—Determining S-Wave Velocity

To calculate either of the CCP binning profiles shown on FIG. 29, theprocessing system is configured to determine the S-wave velocity withinthe geology that is being imaged. If the alternate option of creatingconverted-mode images with prestack migration techniques is used (FIG.30), the processing system is configured to generate reliable estimatesof S-wave velocities within the rocks that are illuminated by theseismic data. Determining the S-wave velocity for calculating SV-P imagepoints can be done in the same way that S-wave imaging velocities aredetermined for P-SV data. Methods for determining S-wave velocity forcalculating converted-mode image points comprise:

-   -   1. Use 3-component vertical seismic profile (VSP) data acquired        local to the seismic image area to calculate interval values of        V_(P) and V_(S) velocities.    -   2. Use dipole sonic log data acquired local to the seismic image        space to determine V_(P) and V_(S) velocities.    -   3. Combine laboratory measurements of V_(P)/V_(S) velocity        ratios for rock types like those being imaged with seismic-based        estimates of P-wave velocities to calculate S-wave velocities.    -   4. Calculate CCP binning profiles for a variety of V_(P)/V_(S)        velocity ratios, make separate stacks of converted-mode data for        each CCP trend, and examine the series of stacked data to        determine which CCP profile produces the best quality image.

Any of these methods will provide reliable S-wave velocities to use forbinning SV-P data. Alternate methods may be used.

Comparison of SV-P Data to P-SV Data

This application shows there are several similarities between SV-P dataand P-SV data, according to some exemplary embodiments. There are alsodifferences between the two wave modes, according to some exemplaryembodiments. Some of these similarities and differences are listed inthe table shown as FIG. 31. Similarities between SV-P and P-SV datainclude items 1, 5, and 6 (same energy source, same velocity analysisstrategy, and same normal moveout (NMO) velocity behavior). Differencesinclude items 2, 3, 4, and 7 (different receivers, different imagecoordinates, different CCP profiles, and different polarity behavior).

SV-P Data Processing Apparatus

Referring now to FIG. 32, a data processing system for processing SV-Pdata will be described. System 3200 is configured to extract SV sheardata from vertical-sensor responses. System 3200 comprises a digitalcomputation system 3202, such as a personal computer, UNIX server,single workstation, high-end cluster of workstations, or other computingsystem or systems. System 3202 comprises sufficient processing power toprocess large quantities of complex seismic data. A mass storage device3204 or other memory is coupled to digital computation system 3202,which is configured to receive data from the field recorders or sensorsstored on a digital media 3202, such as a memory card, hard drive, orother memory device. Mass storage device 3204 is configured to downloador receive the multi-component seismic data from digital media 3206 andto store the data in a database.

In this embodiment, digital media 3206 comprises data received from avertical sensor using a field recorder or receiver. The data on digitalmedia 3206 may have been acquired recently or days, months, or years inthe past. The data may have been recorded using a vertical force sensorhaving a sufficient listening time, for example of at least 5 seconds,at least 8 seconds, at least 10 seconds, or other periods of time. Thedata may have been acquired without the expectation of recovering SV-Pdata by the entity handling the acquisition of data and withoutknowledge of the presence of SV-P data in the data acquired from seismicreflections.

The remaining elements in FIG. 32 may comprise any of the embodimentsdescribed hereinabove with reference to FIG. 19, or other components.Software library 3212 may comprise processing algorithms configured toprocess the data according to any of the principles describedhereinabove, for example with reference to FIGS. 21-31, and FIGS. 34 and35 below.

SV-P Data Acquisition

Referring now to FIG. 33, a diagram of a data acquisition system 3300and method for acquiring SV-P data from a vertical-force source usingsurface-based sensors will be described. A vertical-force seismic source3302 is disposed on, near, or within a shallow recess of the Earth'ssurface 3304, which may comprise relatively high-velocity layers orportions or relatively low-velocity layers or portions. Source 3302 isconfigured to impart a vertical-force to surface 3304 to provide seismicwaves into Earth media 3306. Source 3302 may comprise a verticalvibrator, shot-hole explosive, vertical-impactor, air gun, verticalweight-dropper or thumper, and/or other vertical-force sources. In thisexample, vertical-force source 3302 produces compressional P mode andboth fundamental shear modes (SH and SV) in Earth 3306 directly at apoint of application 3308 of the vertical-force source. In thisembodiment, at least some of the SH and SV shear waves are generated atsource 3302 and not by subsurface conversion caused by portions of Earthmedia 3306. The frequency waves may be provided in a frequency sweep ora single broadband impulse. A vertical-force source may be used withoutany horizontal-force sources.

A seismic sensor 3310 is along the Earth's surface, which may includebeing disposed on, near, or within a recess of the Earth's surface 3304.For example, in one embodiment, shallow holes may be drilled and sensors3310 deployed in the holes to avoid wind noise, noise produced by rainshowers, etc. Sensor 3310 is configured to detect or sense upgoing wavemodes, reflected from subsurface sectors, formations, targets ofinterest, etc. In this embodiment, sensor 3310 may comprise avertical-response sensor (either single-component or 3-componentpackage) configured to sense compressional P modes and, as describedherein, other modes such as SV-P (e.g., direct SV-P). In one embodiment,sensor 3310 may comprise a vertical-response sensor withouthorizontal-response sensors, for example only a single,vertical-response sensor. Various arrays and configurations of sources3302 and sensors 3310 may be implemented in different embodiments.

The remaining elements in FIG. 32 may comprise any of the embodimentsdescribed hereinabove with reference to FIG. 17, or other components.

Data Processing in Low-Velocity Earth Surface

Referring now to FIG. 34, a flow diagram illustrating a method 3400 ofprocessing vertical sensor data for low-velocity Earth surface will bedescribed. The method may be operable on one or more processingcircuits, such as digital computation system 3202. The method 3400 mayuse similar techniques to those described above with reference to FIG.20, which contains further explanation of some of the processingprocedures described in FIG. 34. At a block 3402, a processing circuitis provided with mixed P-P and SV-P modes in vertical-sensor data fromacquisition steps described previously. At block 3404, the processingcircuit is configured to or programmed to segregate, separate orotherwise remove P-P and SV-P mode data by applying velocity filters toreject or filter out improper wave-mode propagation velocities.

At a block 3406, the processing circuit is configured to determine NMO,stacking and/or migration velocities for P-P and SV-P modes. Separatevelocity analyses should be done for positive-offset SV-P data and fornegative offset SV-P data. The processing circuit performs separatelyvelocity analyses for positive-offset data and negative-offset data todetermine how the magnitudes of interval velocities differ in these twooffset domains. If there is no lateral variation in P and SV velocitiesaround a source station, there is no need to do two separate SV-Pvelocity analyses—one velocity analysis for positive-offset data, and asecond velocity for negative-offset data. In such a simple,uniform-velocity Earth, positive-offset SV-P reflections andnegative-offset SV-P reflections have the same velocity curvatures, anda velocity analysis done in one offset domain can be used for theopposite-azimuth offset domain. However, it is rare for there to not belateral variations in P and SV velocities around a source station asillustrated on FIG. 27. When layer velocities vary laterally for anyreason, positive-offset and negative-offset SV-P data should undergoseparate velocity analyses as previously discussed using FIG. 27. Toensure lateral velocity variations are accounted for, converted-modedata are processed as two separate data sets. One data set involves onlypositive-offset data, and the second data set involves onlynegative-offset data. Velocity filtering may be done separately forpositive-offset data and negative-offset data to determine offsetdependent interval velocities that can be used to image SV-P data.Velocity filtering may be done separately for positive-offset data andnegative-offset data to output SV-P reflection data corresponding to thecalculated SV-P velocities. The velocities used in some embodiments arethe magnitudes of interval velocities and average velocities needed tostack and/or migrate SV-P data. These velocities may have no algebraicsign.

At a block 3408, static corrections are applied to improve reflectoralignment. These corrections involve time shifts of data acquired ateach source and receiver station. Because these time shifts are appliedto an entire data trace, they are termed static corrections todifferentiate them from dynamic time adjustments done by otherprocesses. One static correction removes timing differences caused byvariations in station elevations by adjusting time-zero on each datatrace to mathematically move all source and receiver stations to acommon datum plane. A second static correction removes timingdifferences cause by different velocities being local to differentsource and receiver stations. The end result of these static correctionsis an improvement in reflection continuity.

At a block 3410, any one of many noise rejection procedures may beapplied to the data to improve the signal-to-noise ratio. Some noiserejection options may be simple frequency filters. Others may be moresophisticated tau-p, f-k, or deconvolution procedures. At block 3410,multiple attenuation may be applied to attenuate noise attributable tomultiples.

As described, multiple methods are available for processing the data toidentify SV-P mode data and use it for generating an image, such asMethod 1 and Method 2 described above. If Method 1 is used, at a block3412, the processing circuit is configured to stack (or sum) P-P, SV-Ppositive-offset and SV-P negative-offset data separately using eitherCCP coordinates or ACP coordinates. At a block 3414, the processingcircuit is configured to sum SV-P positive-offset and SV-P negativeoffset stacks. Block 3414 may use a CCP binning process. At a block3416, the processing circuit is configured to migrate post-stack data tomake four images: a P-P image, an SV-P positive offset image, an SV-Pnegative-offset image and an SV-P summed image.

If Method 2 is used, at a block 3420, the processing circuit isconfigured to do separate pre-stack time migrations, depth migrations,or reverse-time migrations of P-P, SV-P positive offset data and SV-Pnegative-offset data and, at a block 3422, sum SV-P positive-offset andSV-P negative-offset images.

At block 3418, an operator views the images created by either or both ofMethod 1 and Method 2 and makes a determination as to whether the imagequality is acceptable. If not, the process returns, for example to block3406 for further processing. An operator may adjust static corrections,recalculate velocities, etc. Alternatively, block 3418 may be automatedto not require a person to make the determination, but rather to havethe processing circuit make the determination based on certain imagegoals.

Data Processing in High-Velocity Earth Surface

Referring now to FIG. 35, a flow diagram illustrating a method 3500 ofprocessing vertical sensor data for high-velocity Earth surface will bedescribed. The method 3500 may use similar techniques to those describedabove with reference to FIGS. 20 and 34, which contains furtherexplanation of some of the processing procedures described in FIG. 35.As explained previously, in high-velocity Earth surface situations,upgoing SV data can be detected by a vertical-force source, meaning thatthe data that can be processed into images now includes the SV-SV modeand the P-SV mode.

At a block 3502, a processing circuit is provided with mixed P-P, SV-SV,P-SV and SV-P modes in vertical-sensor data from acquisition stepsdescribed previously. At block 3504, the processing circuit isconfigured to or programmed to segregate, separate or otherwise removeP-P, SV-SV, P-SV and SV-P mode data by applying velocity filters toreject or filter out improper wave-mode propagation velocities.

At a block 3506, the processing circuit is configured to determine NMO,stacking and/or migration velocities for P-P, SV-SV, P-SV and SV-Pmodes. Separate velocity analyses are required for positive-offset P-SVand SV-P data and for negative offset P-SV and SV-P data.

At a block 3508, static corrections are applied to improve reflectoralignment, as described with reference to block 3408. At a block 3510,any one of many noise rejection procedures may be applied to the data toimprove the signal-to-noise ratio. Some noise rejection options may besimple frequency filters. Others may be more sophisticated tau-p, f-k,or deconvolution procedures. At block 3510, multiple attenuation may beapplied to reduce noise attributable to multiples.

As described, multiple methods are available for processing the data toidentify SV-P mode data and use it for generating an image, such asMethod 1 and Method 2 described above. If Method 1 is used, at a block3512, the processing circuit is configured to stack (or sum) P-P, SV-Ppositive-offset and SV-P negative-offset data and P-SV positive-offsetdata and P-SV negative-offset data, each to be stacked separately. At ablock 3514, the processing circuit is configured to sum SV-Ppositive-offset and SV-P negative offset stacks and separately sum P-SVpositive-offset and P-SV negative-offset stacks. At a block 3516, theprocessing circuit is configured to migrate post-stack data to makeeight images: a P-P image, an SV-P positive offset image, an SV-Pnegative-offset image, an SV-SV image, a P-SV positive offset image, aP-SV negative offset image, P-SV summed image and an SV-P summed image.

If Method 2 is used, at a block 3520, the processing circuit isconfigured to do separate pre-stack time migrations, depth migrations,or reverse-time migrations of P-P, SV-SV, SV-P and P-SV positive offsetdata and SV-P and P-SV negative-offset data and, at a block 3522, sumSV-P positive-offset and SV-P negative-offset images.

At block 3518, an operator views the images created by either or both ofMethod 1 and Method 2 and makes a determination as to whether the imagequality is acceptable. If not, the process returns, for example to block3506 for further processing. An operator may adjust static corrections,recalculate velocities, etc. Alternatively, block 3518 may be automatedto not require a person to make the determination, but rather to havethe processing circuit make the determination based on certain imagegoals.

As illustrated in a comparison of FIGS. 20, 34 and 35, it is notnecessary in the methods of FIGS. 34 and 35 to change the polarity ofnegative-azimuth SV-P data to agree with the polarity ofpositive-azimuth SV-P data when dealing with vertical-sensor data. Also,two separate velocity analyses are performed when processing SV-P dataas in the methods of FIGS. 34 and 35 because that imaging is based oncommon-conversion point concepts, not on common-midpoint concepts asused in the methods of FIG. 20. In the methods of FIGS. 34 and 35, onevelocity analysis is done for positive-azimuth data and a secondanalysis is done for negative-azimuth data (as explained with referenceto FIG. 27).

Extracting Shear Wave Information from Towed Cable Marine Seismic Data

According to one or more embodiments, S-wave information can beextracted from towed-cable marine data when certain data-processingsteps are implemented by a data processor.

In some embodiments, a single-component compressional P wave sensor isused as a receiver to receive both P-P and SV-P modes.

In some embodiments, multi-component sensors are not needed.

In some embodiments, the single-component compressional P wave sensor isdisposed in the water well above the sea floor, within the water column,for example being towed behind a boat. The single-componentcompressional P wave sensor may be similarly disposed. In someembodiments, neither the P wave source nor P wave receiver are disposedon, in contact with, or within the seafloor.

In some embodiments, an SV-P mode is sensed in a marine environment andprocessed to generate a visual image of one or more formations beneaththe sea floor.

In some embodiments, a virtual source and/or virtual receiver are usedin the acquisition of the seismic data, wherein the virtual source orreceiver is computationally derived from data from an actual source orreceiver, respectively.

In some embodiments, a single-component or one-component P wave sourcetowed by a boat generates a downgoing P wave which upon contact with theseafloor generates a downgoing SV shear wave mode directly at the pointof contact of the P wave with the seafloor, at the seafloor surface. Insome embodiments, this downgoing SV mode is not a converted shear modecreated by reflections of a downgoing P mode off formations below thesea floor, but is instead an SV mode generated directly at the point ofcontact of the P wave with the seafloor.

In some embodiments, image processing is based on towed-cable marinedata in which there are no receivers other than those in the towedcable.

Marine Seismic Sources

Marine seismic data are generated by towing a seismic source below thesea surface. Although some seismic sources, primarily shear-wavegenerators, have been devised that function on the seafloor,seafloor-positioned sources are generally not used to generate seismicreflection data because of deployment challenges and environmentalregulations that protect seafloor biota. Thus, marine seismic dataacquisition typically involves sources that can be towed at a desireddepth below the sea surface (e.g., 3 to 15 meters or other depths).

One energy source that may be used in marine environments is a towed airgun. Air gun sources can be a single air gun, an array of air guns, orseveral arrays of air guns with each array containing numerous air guns.Sources other than air guns can be encountered when legacy marine dataare considered. Among source types that may be used to acquire marineseismic data are vibrators, explosives, sparkers, and various mechanismsthat produce impulsive wavelets in the water column. The embodimentsdescribed herein may use any types of source, such as towed sources,used to generate marine seismic reflection data.

Marine Seismic Sensors

Marine seismic data may be recorded by towing an array of hydrophonesbelow the sea surface. These hydrophones are embedded in one or morelong cables that trail behind a seismic recording boat. Geophones and/oraccelerometers are used in some towed-cable systems. Marine seismic datacan also be acquired with stationary sensors placed on the seafloor.Stationary seafloor sensors typically involve combinations ofhydrophones and geophones or combinations of hydrophones andaccelerometers. The embodiments described herein may use any type ofsensor, such as towed-cable sensors, whether the sensors comprisehydrophones, geophones, accelerometers, etc.

Virtual Sources and Receivers

Referring now to FIG. 38, a diagram illustrates exemplary components ofa marine seismic data-acquisition system and raypaths of compressional(P) and vertical shear (SV) seismic modes generated during seismicillumination of sub-seafloor geology. P-wave raypaths are shown as solidlines. S-wave raypaths are shown as dashed lines. A source 3800 is towedby a boat 3802. Only P waves propagate in the water layer because waterhas a shear modulus of zero and cannot support shear-mode propagation.When the downgoing P mode 3800 produced by a marine energy sourceimpinges on the seafloor 3804 at any incident angle other than truevertical, two downgoing modes—a P mode 3806 and an SV mode 3808—arecreated at the seafloor interface 3804 and continue to propagatedownward and illuminate sub-seafloor targets, such as target 3812. Thedowngoing P raypath 3800 in the water layer 3812 originates at a realseismic source 3800. The origin point 3810 of the downgoing SV raypathat the seafloor is a virtual seismic source. The acquisition andprocessing described herein exploits the downgoing SV mode 3808 producedat virtual-source coordinates along seafloor 3804.

The embodiment of FIG. 38 may use any type of towed marine energysources, any type of seismic sensors, and may use sensor stations thatare towed in the water layer and/or stationary sensors on the seafloor.

Referring now to FIG. 39, a simplified version of the diagram of FIG. 38illustrates the wave physics of exemplary embodiments.

-   -   A is the real seismic source where a downgoing P wave is        generated.    -   B is the position of the virtual source on the seafloor where,        by downward wavefield extrapolation, the downgoing P wave from        source A segregates into downgoing P and SV transmitted wave        modes and an upgoing P reflected mode. The upgoing P reflection        from seafloor coordinate 3810 is not shown.    -   C is a reflection point from a sub-seafloor target where the        downgoing SV from virtual source B creates an upgoing P        reflection event, as described herein with reference to, for        example, FIGS. 21 through 25, 27, etc.    -   D is the position of a virtual receiver created when the upgoing        P reflection recorded by towed-sensor E is projected downward to        the seafloor by wavefield extrapolation, as will be described        below.    -   E is a real, towed receiver that records the upgoing P        reflection from target point C.

Downward Wavefield Extrapolation

As illustrated in FIG. 39, real source A generates a downgoing P wavethat reaches the seafloor and creates a virtual source. Any coordinatealong a raypath associated with a propagating seismic wave mode can bedefined as the position of a virtual source or a virtual receiver forthat wave mode. For this reason, the position of a virtual source inthis application may be defined by downward extrapolation of a seismicwavefield from the position of an actual towed marine seismic source toa desired source-origin point on or near the seafloor, and the positionof a virtual sensor may be defined by extrapolating a seismic wavefielddownward from a real towed seismic receiver to a preferred location forthat receiver on or near the seafloor. For an explanation of recentvirtual source/receiver principles, see, for example, U.S. Pat. No.7,706,211 to Bakulin et al. titled “Method of Determining a SeismicVelocity Profile” and U.S. Patent Application Publication No.2010/0139927 published Jun. 10, 2010 to Bakulin et al. titled “Method ofImaging a Seismic Source Involving a Virtual Source, Methods ofProducing a Hydrocarbon Fluid, and a Computer Readable Medium.”Similarly, the SV-P wave from virtual source B is received at point D,which may be a virtual receiver. Point D becomes a virtual receiver byway of wavefield extrapolation processing. Downward wavefieldextrapolation may be used to transform data generated by a real sourceand recorded by a real receiver to data equivalent to that generated bya deeper source and recorded by a deeper receiver. In this manner,virtual sources and virtual receivers may be computationally,numerically, or mathematically created, though in alternativeembodiments other techniques may be used.

Downward wavefield extrapolation is used for wave-equation migration ofseismic data, whether migration is done in the depth domain or in theimage-time domain. In one embodiment, wavefield extrapolation may beimplemented as described in Wapenaar, C. P. A., and A. J. Berkhout,1989, Elastic wavefield extrapolation—redatuming of single- andmulti-component seismic data: Elsevier Science, 468 pages. Theprinciples of wavefield extrapolation and computational procedures usedto perform the data transformations described in Wapenaar may be used inan exemplary embodiment. The processing of waveforms may compriseredatuming sources and receivers, and redatuming that applies to Swavefields as well as P wavefields. In another embodiment, the wavefieldextrapolation process of U.S. Pat. No. 7,035,737 to Ren, J., 2006,Method for seismic wavefield extrapolation, may be used. The portions ofthis patent describing how to do wavefield extrapolation using avariable extrapolation step size followed by phase-shifted linearinterpolation of the extrapolated wavefield are expressly incorporatedherein by reference. Alternative methods and procedures of wavefieldextrapolation may be used in one or more of the embodiments describedherein, and reference to wavefield extrapolation herein is not to beconstrued as limiting to any particular method or algorithm.

According to some embodiments, wavefield extrapolation may refer to anyprocess by which the downgoing, P-only, wavefield produced by a towedmarine seismic source is computationally or numerically replaced bydowngoing P and SV wavefields produced by a virtual source at aninterface illuminated by the downgoing, real-source, P-wavefield.Wavefield extrapolation may also refer to any process by which theupgoing, P-only wavefield received at towed receiver E iscomputationally replaced by virtual receiver D on the seafloor. In oneembodiment, the interface where a virtual source should becomputationally positioned is the seafloor. However, according to anexemplary embodiment, a virtual source could be computationallypositioned below the seafloor or even above the seafloor as long as themedium below the source station physically has, or is numericallyassigned, a non-zero shear modulus that will allow a downgoing SV modeto propagate.

Referring to FIG. 39, downward wavefield extrapolation is used in thisembodiment to migrate data generated by real towed-source A and recordedby real towed-receiver E downward so that the data are transformed todata that would have been generated by virtual-source B on the seafloorand recorded by virtual-receiver D also on the seafloor.

Marine Shear Waves

An example of a P-SV reflection is shown on FIG. 38 by the downgoing Praypath 3806 from the towed source that converts to an upgoing SVraypath 3816 at reflection point RP2. Because S-waves cannot propagatein water, this upgoing SV mode must be recorded by a multicomponentsensor, preferably a 4-component (4C) sensor package that has horizontalgeophones or accelerometers and is deployed on the seafloor at position4C3.

According to one embodiment, a system and method involves acquiring andprocessing an SV-P mode in a marine seismic application, which is anevent comprising a downgoing SV raypath produced at the virtual seafloorsource position 3810 that converts to an upgoing P raypath at reflectionpoint RP1. In FIG. 38, the SV-P mode is illustrated for example by SVraypath 3808 and P raypath 3814. An SV-P mode is the inverse of the P-SVmode utilized by marine geophysicists. Because this upgoing P raypathextends upward to towed sensor H1, SV-P data are embedded inconventional towed-cable marine data (e.g., legacy data). No seafloorsensor is required to capture SV-P data, although the technology appliesif seafloor sensors are used rather than towed-cable sensors.

Positive-Offset and Negative-Offset Data

Raypaths involved in positive-offset and negative-offset marine SV-Pimaging are illustrated on FIG. 40. V_(P) and V_(S) velocities in FaciesA are different than they are in Facies B. Straight raypaths are drawnfor simplicity.

In this diagram, SV-P data generated at virtual source A and recorded atvirtual receiver A are labeled SV_(A) for the downgoing SV mode andP_(A) for the upgoing P mode. The offset direction from virtual source Ato virtual receiver A is arbitrarily defined as positive offset. Whenthe positions of source and receiver are exchanged, creating virtualsource B and virtual receiver B, the source-to-receiver offset directionreverses and is defined as negative offset. The raypath fornegative-offset SV-P data is labeled SV_(B) for the downgoing SV modeand P_(B) for the upgoing P mode. The polarities shown for the downgoingSV particle-displacement vector conform to the polarity conventionestablished by Aki and Richards (1980) and documented by Hardage et al.(2011). Note that for both positive-offset data and negative-offsetdata, the vertical component of the particle-displacement vectors forthe upgoing P modes are in the same direction (pointing up), hence thereis no change in SV-P data polarity between positive-offset data andnegative-offset data.

The consideration of positive-offset and negative-offset data is used inland-based seismic data acquisition where receivers extend in allazimuths away from a source point. The possibility of positive-offsetand negative-offset data is also considered for marine seismic data.Most towed-cable marine seismic data involve only positive-offset databecause the source is usually positioned in front of the receiver cable(FIG. 41 at (a)). However, a source could be attached to a separate boattrailing at the rear of a towed receiver cable (FIG. 41 at (b)). In sucha case, the data would be negative-offset data. In modern marinesurveys, source boats often precede and trail towed cables as shown onFIG. 41 at (c), and the recorded data then involve both positive-offsetand negative-offset data.

SV-P Velocity Analysis

One or more embodiments described herein may comprise performing avelocity analysis as a data-processing step when constructing seismicimages. When converted modes are involved, two velocity analyses can bedone—one analysis for positive-offset data and a second analysis fornegative-offset data. The reason for this dual-offset-domain velocityanalysis is illustrated on FIG. 40 which shows two distinct rock faciesA and B between two source and receiver stations. Laterally varying rockconditions such as shown on this diagram are found in many marinebasins. For purposes of illustration, assume the P and S velocities inFacies A are significantly different from the P and S velocities inFacies B. The travel time required for a positive-offset SV-P event totravel raypath SV_(A)-P_(A) is not the same as the travel time for anegative-offset SV-P event to travel raypath SV_(B)-P_(B). Thisdifference in travel time occurs because the SV_(A) mode is totally inFacies A, but the SV_(B) mode is almost entirely in Facies B, Likewise,all of mode P_(B) is in Facies A, but mode P_(A) has significant travelpaths inside both Facies A and Facies B. Because travel times differ inpositive-offset and negative-offset directions, seismic intervalvelocities determined from positive-offset data differ from intervalvelocities determined from negative-offset data. Thus, in someembodiments, one velocity analysis is done on positive-offset data, anda separate velocity analysis is done for negative-offset data.

FIG. 42 illustrates SV-P and P-SV CCP imaging principles. Curve CCP1shows the trend of common-conversion points for P-SV data. Curve CCP2shows the trend of common-conversion points for SV-P data. ACP1 and ACP2are asymptotic conversion points for trends CCP1 and CCP2, respectively.CCP1 and CCP2 are mirror images of each other relative to the commonmidpoint CMP for this source-receiver pair.

Constructing SV-P Images

The processing of SV-P data for generating SV-P images can be done in anumber of ways, such as: (1) by common-conversion-point (CCP) binningand stacking of SV-P reflections, followed by post-stack migration ofthe stacked data, or (2) by implementing prestack migration of SV-Preflections. Method 2 (prestack migration) is a more rigorous approach;method 1 (CCP binning/stacking and post-stack migration) is lower cost.To perform CCP binning and migration of SV-P data, CCP coordinates ofSV-P image points relative to this common-midpoint between a source anda receiver are mirror images of CCP image points associated with P-SVdata, as illustrated on FIG. 42. The SV-P data-processing strategy maybe based on this mirror-image symmetry of CCP image-point profiles forP-SV and SV-P modes.

Because positive-offset and negative-offset SV-P data have differentvelocity behaviors, two separate CCP binning/stacking steps are done tocreate an SV-P stacked image. In Step 1, positive-offset data are binnedand stacked into an image using velocities determined frompositive-offset data, and in Step 2, negative-offset data are binned andstacked into a second image using velocities determined fromnegative-offset data. The final SV-P image is the sum of these twoimages. This same dual-image strategy may implemented when binning andstacking P-SV marine data. The three stacked images (positive-offset,negative-offset, and summed offsets) can be migrated and used ingeological applications. As documented by Hardage et al. (2011) relativeto P-SV imaging, some geologic features are sometimes better seen in oneof these three images than in its two companion images. Thus all threestacked and migrated SV-P images may be used in geologicalinterpretations.

Marine SV-P Data Processing: Imaging Method 1—CCP Binning, Stacking, andPost-Stack Migration

Some commercial seismic data-processing software that can be purchasedor leased by the geophysical community can calculate converted-modeimage coordinates called asymptotic conversion points, which areabbreviated as ACP. Two examples are Vista seismic data processingsoftware, sold by Geophysical Exploration & Development Corporation,Alberta, Canada and ProMAX seismic data processing software, sold byHalliburton Company, Houston, Tex. Such software calculatesconverted-mode image coordinates called asymptotic conversion points,which are abbreviated as ACP. An ACP is an image coordinate where thetrend of correct CCP image points for a specific source-receiver pairbecomes quasi-vertical (FIG. 42). Deep geology is correctly imaged usingP-SV data binned by ACP principles, and would also be correctly imagedby SV-P data binned using ACP concepts that are adjusted for SV-P data.However, shallow geology is not correctly imaged for either P-SV data orSV-P data when ACP binning methods are used. True CCP binning canproduces correct stacked images of both shallow and deep geology forconverted modes appropriate for post-stack migration. On FIG. 42, theasymptotic conversion point for the P-SV mode is labeled ACP1, and theasymptotic conversion point for the SV-P mode is labeled ACP2. Neitherimage point is correct except where their associated CCP binning profileis quasi-vertical (i.e., for deep targets). As has been emphasized,these two image points are mirror images of each other relative to thecommon midpoint (point CMP on FIG. 42) for any source-receiver pairinvolved in a seismic survey.

One exemplary method of producting CCP or ACP binning for marine SV-Pdata comprises adjusting software that performs CCP binning for marineP-SV data so that the coordinates of sources and receivers are exchangedwhen determining image-point coordinates. Referring to thesource-receiver pair drawn on FIG. 42, an exchange of stationcoordinates has the effect of moving the receiver station to the sourcestation and the source station to the receiver station. Software used toprocess P-SV data will then calculate the image point trend labeled CCP2rather than the trend labeled CCP1. Using coordinates specified byprofile CCP2 to bin marine SV-P reflections extracted from marinetowed-sensor data will produce SV-P images, which should be equal inquality to what is now achieved with marine P-SV data.

Marine SV-P Data Processing: Imaging Method 2—Prestack Migration

According to an alternative embodiment, prestack migration can be doneto create a time-based seismic image or a depth-based seismic image.Referring to FIG. 43, prestack migration can be done by numericallypropagating a specific seismic wavefield downward from each sourcestation to illuminate geologic targets, and then numerically propagatinga specific seismic wavefield upward from reflecting interfaces to eachreceiver station.

The specific wavefields used in prestack migration may be created byapplying velocity filters to seismic data so that reflection eventshaving only a predetermined velocity behavior remain after velocityfiltering. Velocity wavefields are listed in the table of FIG. 43. Thespecific velocity behaviors of interest in this exemplary embodiment arethose downgoing and upgoing velocities associated with P-P and SV-Pseismic modes. These modes are listed as option 1 and option 3 on FIG.43. The result of prestack migration is an image of geologic interfacesseen by each specific seismic mode (P-P and SV-P). For simplicity, onlyone source station and only one receiver station are shown on FIG. 43.

As indicated by the table on FIG. 43, prestack time migration, depthmigration, or reverse-time migration processing can create a SV-P imageif the velocity of the downgoing wavefield is that for a propagating SVwavefield and the velocity of the upgoing wavefield is that for a Pwavefield.

In FIG. 43, a time-space distribution of velocities for a specificseismic mode is defined so that a specific downgoing wavefield (D) canbe propagated through this Earth velocity model from every sourcestation to illuminate targets. A second time-space distribution ofvelocities for a second specific seismic mode is then imposed topropagate that specific upgoing wavefield (U) to every receiver station.The combinations of downgoing and upgoing velocities that can beimplemented for towed-cable marine seismic in this exemplary embodimentinvolve options 1 and 3 listed in the table.

Prestack Time Migration

Prestack time migration of seismic data may be done by constructingcommon-source trace gathers and calculating where individual data pointsin each trace of each shot gather need to be positioned in seismic imagespace. An exemplary calculation is illustrated in FIG. 44. In thisdiagram, S is the position of a source station in migrated image space,R is the position of a specific receiver station in migrated imagespace, and A is the position of an image point that is beingconstructed.

The position of image point A is defined as space-time coordinates(X_(A),t). To perform prestack time migration, coordinate X_(A) isdefined by a data processor, and time coordinate t then is incrementedfrom 0 to t_(MAX), where t_(MAX) is the length of the migrated datatrace. The diagram shows the migration of only one data point from onlyone trace of only one shot gather. The objective is to calculate thetime coordinate T of the data sample from the S-to-R data trace thatneeds to be placed at image-space coordinates (X_(A), t).

The calculation is done by the two square-root equations shown on FIG.44 and shown below:

$T_{SA} = \sqrt{\left( \frac{t}{2} \right)^{2} + \left( \frac{D_{SA}}{V_{SA}} \right)^{2}}$$T_{AR} = \sqrt{\left( \frac{t}{2} \right)^{2} + \left( \frac{D_{AR}}{V_{AR}} \right)^{2}}$

in which:

-   -   A=Image point    -   t=Image-trace time coordinate    -   X_(A)=Image-trace coordinate    -   D_(SA)=Horizontal distance from S to A    -   D_(AR)=Horizontal distance from A to R    -   T_(SA)=One-way time from S to A    -   T_(AR)=One-way time from A to R    -   V_(SA)=RMS velocity for downgoing mode at (X_(A), t)    -   V_(AR)=RMS velocity for upgoing mode at (X_(A), t)    -   T=T_(SA)+T_(AR)=Time coordinate of data sample placed at image        coordinates (X_(A), t)

FIG. 44 illustrates the double square root calculation used in prestacktime migration of seismic data. Image coordinate X_(A) is defined by thedata processor. Image time t varies from zero to the maximum timecoordinate of the migrated data. Velocities V_(SA) and V_(AR) are rmsvelocities determined by a separate velocity analysis and preserved in afile that can be accessed to calculate time coordinate T of the datasample that needs to be moved to image coordinate at (XA, t).

One square-root equation calculates one-way time T_(SA) for thedowngoing raypath from S to A. The second square-root equationcalculates the one-way time T_(AR) for the upgoing raypath from A to R.The time coordinate T of the data sample from shot-gather trace S-to-Rwhich needs to be placed at migration coordinates (X_(A), t) is the sumof T_(SA) and T_(AR). This prestack time-migration procedure is calledthe double square-root calculation. An assumption built into thecalculation is that down and up one-way travel times can be representedas travel times along straight, not curved, raypaths.

Another view of prestack time migration is shown as FIG. 45. Thisdiagram illustrates a process of prestack time migration, according toan exemplary embodiment. In step 1, a data processor or processingcircuit is configured to select from a memory a particular data tracerecorded by receiver R of a particular Shot Record for performingprestack time migration. Image coordinate X_(A) defined by the dataprocessor may or may not coincide with the position of a receiverstation. In this example, X_(A) is not coincident with a receiverstation. In step 2, the data processor is configured to build onemigrated image trace at image-space coordinate X_(A). Image-timecoordinate t is a time coordinate of this migrated data trace. RaypathsSA and AR shown relative to step 2 are the raypaths from FIG. 44.

In step 3, the data processor is configured to access from memory avelocity file that defines rms velocities at every coordinate in themigrated image space. In step 4, one-way travel times T_(SA) and T_(AR)defined by the square-root equations on FIG. 44 are calculated to definethe time coordinate T of the input data trace that needs to be moved toimage coordinates (X_(A), t). In step 5, the data processor isconfigured to move the data sample from shot-gather data space tomigrated image space.

Referring now to FIG. 46, a system and method for processing marine SV-Pdata is shown, according to an exemplary embodiment. This system isconfigured to produce (1) trace gathers, and (2) images of sub-seafloorgeology that describe S-wave propagation through imaged strata. At block1, towed-cable seismic data are retrieved from a storage device ormemory. The seismic data may have been acquired using any of theprocesses described herein, such as those described with reference toFIGS. 38, 39 and/or 41. As stored in the storage device, the seismicdata may comprise P-P data as well as shear mode data, such as SV-Pdata, said P-P and SV-P data having been received through a towedreceiver or other sensor configured to measure compressional P waves togenerate the seismic data.

At block 2, the data processor is configured to extrapolate the Pwavefields of the seismic data downward to create virtual sources andvirtual receivers on the seafloor, for example as described above withreference to FIG. 39. At block 3, the data processor is configured toperform data conditioning steps, such as frequency filtering,deconvolution, de-multiple, spectral whitening and/or other dataconditioning processes that adjust the appearance of seismic data.Deconvolution may refer to a numerical process that restores the shapeof a seismic wavelet to the shape it had before it was distorted byinterfering wavelets or by any phase and amplitude changes caused bysensor responses, equipment filtering, background noise, etc.De-multiple may refer to a numerical process that removes interbedmultiple reflections from seismic data. De-multiple is one type ofdeconvolution, i.e., the removal of interfering wavelets. Spectralwhitening may refer to a process of adjusting the frequency spectrum ofa seismic wavelet so that the spectrum is as flat as possible over thewidest possible frequency range. Wide, flat spectra result in compacttime wavelets that have optimal resolution. At block 4, the dataprocessor is configured to determine SV-P velocities separately forpositive-offset data and negative-offset data if the sources werepositioned in front of and behind towed receivers during the acquisitionof the data being processed, as described for example with reference toFIGS. 40 and 41 herein.

As described above, two illustrative image processing methods aredescribed herein, though others may be used. In a first imaging option,at block 5, the data processor is configured to create separate CCPstacks for positive-offset and negative-offset SV-P data. At block 6,the data processor may be configured to sum the positive-offset andnegative-offset SV-P stacks. At block 7, the data processor may beconfigured to apply any desired data conditioning steps, such as thosedescribed above with reference to block 3. At block 8, the dataprocessor is configured to migrate post-stack data to make SV-P and P-Pimages.

If the second imaging option is used, at block 9 the data processor isconfigured to perform separate prestack migrations for positive-offsetSV-P data and negative-offset SV-P data if sources are in front of andbehind towed receivers (either time domain or depth domain). At block10, the data processor is configured to sum positive-offset andnegative-offset SV-P images. At block 11, the data processor isconfigured to apply any desired data-conditioning steps.

Once an image is made by either image processing option 1 or imageprocessing option 2, that image is difficult to compare against normaltowed-cable image because the image uses the seafloor (or near seafloor)as a datum (datum=depth where seismic image time is defined to be zero).In contrast, towed-cable images use sea level as a datum. The imageslook significantly different when the seafloor has considerable slope ortopographic relief. Thus the seafloor datum image can be re-datumed tosea level so image comparisons are easier to do, as shown at block 12.This re-datuming may comprise a time shift of each trace that accountsfor the two-way P-wave travel time through the water layer to theseafloor coordinate where each trace is positioned in SV-P image space.The SV-P image was created by stripping off the water layer. After SV-Pimaging is completed, the processing can then add the water layer backinto the picture.

SV-P Data Acquisition

Referring now to FIG. 47, a diagram of a data acquisition system 4700and method for acquiring SV-P data in a marine environment will bedescribed. A marine towed source 4702 is disposed under, near, or abouta surface of a marine environment, near sea level 4704. Source 4702 istowed by a boat while in operation, while transmitting compressional Pwaves into the water column 4706. Source 4702 is configured to impart animpulsive force to water column 4706 to provide seismic waves to point Aon a seafloor 4708. Source 4702 may comprise an air gun or otherimpulsive or swept-frequency force sources. In this example, source 4702produces compressional P mode, but not shear modes (SH and SV) becausethe shear modulus of water is zero. However, upon contact, encounter, orimpingement of the P mode wavefield with seafloor 4708 at point A, adowngoing P and a downgoing shear wave mode (SV) is produced. In thisembodiment, at least some of the SV shear waves are generated at point Aand not by sub-seafloor mode conversion at sub-seafloor interfaceswithin Earth media 4710.

A seismic sensor 4712, in this case a marine towed sensor, is towed by aboat attached to the sensor by a cable, which also may be disposedunder, near, or about a surface of the marine environment at sea level4704. Sensor 4712 is configured to detect or sense upgoing wavefields,reflected from subsurface sectors, formations, targets of interest, etc.within Earth media 4710 to point B. Upgoing waves within Earth media4710 comprise P-P waves (P waves downgoing from point A and upgoing topoint B) and upgoing SV waves (both SV-SV waves and P-SV waves). Theupgoing SV waves cannot propagate through water column 4706 to marinetowed sensor 4712 and, therefore, only the upgoing P waves reach marinetowed sensor 4712. In this embodiment, sensor 4712 comprises a sensorconfigured to sense compressional P modes and, as described herein,other modes such as SV-P (e.g., direct SV-P). In one embodiment, sensor4712 is a hydrophone, which may be configured to provide an output whichhas no directional information about the waves being sensed. Variousarrays and configurations of sources 4702 and sensors 4712 may beimplemented in different embodiments. Towed sources and receivers may bein constant motion throughout the acquisition of seismic data.

In alternative embodiments, marine towed source 4702 and/or marine towedsensor 4712 may instead by disposed on, at, embedded within or incontact with seafloor 4708. In this case, the sensor may be avertical-force sensor configured to record a vertical response.

Data sensed by marine towed sensor 4712 are configured to be stored by asuitable processing circuit in a digital media or data storage device4714, which may be any type of memory or other data storage devicedescribed herein. Block 4716 illustrates a data processor configured toperform wavefield extrapolation to create virtual SV source A andvirtual P sensor B on seafloor 4708, and/or other processing stepsdescribed herein. One or more of the aspects described with reference toFIG. 17 and FIG. 33 may be used with aspects of FIG. 47 in alternativeembodiments.

Determining S-Wave Velocity

To calculate either of the CCP binning profiles shown on FIG. 42, a dataprocessor may be configured to determine S-wave velocities within thegeological layering that is being imaged. If the second option ofcreating converted-mode images with prestack migration techniques isused, the data processor uses estimates of S-wave velocities within therocks that are illuminated by the seismic data. Determining the S-wavevelocities needed for calculating SV-P image points can be done usingtechniques for determining S-wave imaging velocities when processingP-SV data.

Exemplary methods for determining S-wave velocity needed for calculatingconverted-mode image points include: 1) using vertical seismic profiledata acquired local to the seismic image area to calculate intervalvalues of V_(P) and V_(S) velocities, 2) using dipole sonic log dataacquired local to the seismic image space to determine V_(P) and V_(S)velocities, 3) combining laboratory measurements of V_(P)/V_(S) velocityratios for rock types like those being imaged with seismic-basedestimates of P-wave velocities to back-calculate S-wave velocities, 4)calculating CCP binning profiles for a variety of V_(P)/V_(S) velocityratios, making separate stacks of converted-mode data for each CCPtrend, and examining the series of stacked data to determine which CCPprofile produces the best quality image, or other methods. These methodscan be used to provide reliable S-wave velocities to use for velocityfiltering to define S-wave modes, stacking, and migrating SV-P data.

It is understood that principles, steps, components, or teachings fromany of the embodiments described herein may be combined with otherembodiments described herein to provide yet further embodiments.

In an alternative embodiment, as taught herein, a downgoing P wave thatimpinges on point A on the seafloor generates both an SV shear wave modeand an SH shear wave mode. This is because the vertical component of thedowngoing P wave can be viewed as a low-energy vertical force source atpoint A that produces the radiation patterns shown as FIG. 6. In thisalternative embodiment, seafloor-based sensors, such as 4 component (4C)sensors may be used to receive a variety of upgoing wavemodes and storethem in a memory for further processing.

Various embodiments disclosed herein may include or be implemented inconnection with computer-readable media configured to storemachine-executable instructions therein, and/or one or more modules,circuits, units, or other elements that may comprise analog and/ordigital circuit components (e.g. a processor or other processingcircuit) configured, arranged or programmed to perform one or more ofthe steps recited herein. By way of example, computer-readable media mayinclude non-transitory media such as RAM, ROM, CD-ROM or other opticaldisk storage, magnetic disk storage, flash memory, or any othernon-transitory medium capable of storing and providing access to desiredmachine-executable instructions. The use of circuit or module herein ismeant to broadly encompass any one or more of discrete circuitcomponents, analog and/or digital circuit components, integratedcircuits, solid state devices and/or programmed portions of any of theforegoing, including microprocessors, microcontrollers, ASICs,programmable logic, or other electronic devices. In various embodiments,any number of sources and receivers may be used, from one to hundreds,thousands, or more.

While the detailed drawings, specific examples and particularformulations given describe exemplary embodiments, they serve thepurpose of illustration only. The hardware and software configurationsshown and described may differ depending on the chosen performancecharacteristics and physical characteristics of the computing devices.The systems shown and described are not limited to the precise detailsand conditions disclosed. Furthermore, other substitutions,modifications, changes, and omissions may be made in the design,operating conditions, and arrangement of the exemplary embodimentswithout departing from the scope of the present disclosure as expressedin the appended claims.

1. A method of processing seismic data, the seismic data obtained usinga plurality of single-component towed receivers in a marine environment,the single-component towed receivers configured to measure compressionalP waves, comprising: retrieving seismic data from a storage device, theseismic data comprising P-P data and shear mode data, wherein the P-Pdata and shear mode data were both received at the single-componenttowed receivers; processing the seismic data to extract SV-P shear modedata; and generating shear mode image data based on the extracted shearmode data.
 2. The method of claim 1, wherein the processing comprisesextrapolating wavefields represented by the seismic data downward tocomputationally create virtual sources and virtual receivers on aseafloor in the vicinity of an area imaged by the seismic data.
 3. Themethod of claim 2, wherein the processing comprises determining SV-Pvelocities separately for positive-offset SV-P data and negative-offsetSV-P data.
 4. The method of claim 3, wherein the processing comprisescreating separate common conversion point stacks for the positive-offsetSV-P data and the negative-offset SV-P data, wherein the processingcomprises separately pre-stack migrating the SV-P data forpositive-offset SV-P data and negative-offset SV-P data.
 5. The methodof claim 4, wherein the processing comprises summing the commonconversion point stacks for the positive-offset SV-P data and thenegative-offset SV-P data, wherein the processing comprises post-stackmigrating the SV-P data.
 6. The method of claim 1, wherein the P-P dataand shear mode data were both received at the single-component towedreceivers disposed well above the seafloor within the water columnwithout the use of multi-component geophones, the single-component towedreceivers configured to receive compressional P waves and not shearwaves.
 7. The method of claim 1, wherein the SV-P data is a result ofdown going P waves from towed P wave sources which upon contact with theseafloor generate downgoing SV shear waves directly at the point ofcontact of the P waves with the seafloor at the seafloor surface.
 8. Themethod of claim 1, further comprising: transmitting P waves from P wavesources, wherein the P waves upon contact with the seafloor generatedowngoing SV shear waves directly at the point of contact of the P waveswith the seafloor at the seafloor surface, the downgoing SV shear wavesreflecting off sub-seafloor interfaces as SV-P wave modes; receiving theSV-P wave modes using the single-component towed receivers; and storingthe SV-P wave modes in the data storage device to achieve the seismicdata comprising P-P data and shear mode data.
 9. A method of generatinga shear mode image from marine P-wave seismic data acquired with aplurality of towed single-component P-wave sensors, comprising:retrieving from a storage device seismic data generated by a source andreceived by the towed single-component P-wave sensors, the datacomprising SV-P mode data; extrapolating wavefields represented by theseismic data downward to computationally create virtual sources andvirtual receivers on a seafloor in the vicinity of an area imaged by theseismic data; and processing the extrapolated wavefields to generateshear mode image data.
 10. The method of claim 9, wherein the SV-P modedata is a result of a downgoing P wave from a towed P wave source whichupon contact with the seafloor generates downgoing SV shear wave modesdirectly at the point of contact of the P wave with the seafloor at theseafloor surface.
 11. The method of claim 10, wherein the seismic datawas received at the towed P-wave sensors as they were being towed, thesensors disposed well above the seafloor within the water column withoutthe use of multi-component geophones.
 12. The method of claim 9, furthercomprising: providing a memory programmed to store processed seismicdata, the stored, processed seismic data having been processed fromdirect shear wave mode data, the direct shear wave mode datarepresenting seismic waves which were provided as shear waves directlyat a point of application of a vertical force source and sensed asreflections at one or more geophones; and transferring the stored,processed seismic data to a memory device using a processing circuit.13. The method of claim 12, further comprising transferring the stored,processed seismic data over a wired or wireless network to anothercomputing device over a network interface circuit, using a processingcircuit.
 14. The method of claim 12, wherein the memory device comprisesat least one of a hard drive, a tape drive, a disk drive, optical diskstorage, magnetic disk storage or flash memory.